capital power corporationsignificant events) and fair value adjustments, were $64 million or $0.60...

1

Capital Power Corporation 10423 – 101 Street NW Suite 1200 Edmonton, AB T5H 0E9

Capital Power reports solid third quarter 2019 results Results highlighted by record cash flow generation in the quarter driven by the

execution of the Company’s growth strategy

EDMONTON, Alberta – October 28, 2019 – Capital Power Corporation (TSX: CPX) today released financial results for the quarter ended September 30, 2019. Third Quarter Highlights

• Achieved excellent operating performance with 96% facility availability

• Generated net cash flows from operating activities of $209 million and adjusted funds from operations of $225 million

• Entered into an agreement to acquire full ownership of Genesee 3 through divestiture of share of Keephills 3

• Purchased and cancelled 1.6 million common shares under the Normal Course Issuer Bid Net cash flows from operating activities were $209 million in the third quarter of 2019 compared with $65 million in the third quarter of 2018. Adjusted funds from operations (AFFO) were $225 million in the third quarter of 2019, compared to $156 million in the third quarter of 2018.

Net loss attributable to shareholders in the third quarter of 2019 was $226 million and basic loss per share was $2.25, compared with net income attributable to shareholders of $18 million, and basic earnings per share of $0.08, in the comparable period of 2018. Normalized earnings attributable to common shareholders in the third quarter of 2019, after adjusting for non-recurring items (see Significant Events) and fair value adjustments, were $64 million or $0.60 per share compared with $34 million or $0.33 per share in the third quarter of 2018.

Net cash flows from operating activities were $519 million for the nine months ended September 30, 2019 compared with $317 million for the nine months ended September 30, 2018. Adjusted funds from operations were $427 million for the first nine months of 2019, compared to $317 million in the comparable nine month period last year.

For the nine months ended September 30, 2019, net loss attributable to shareholders was $57 million and basic loss per share was $0.90 per share, compared with net income attributable to shareholders of $127 million, and basic earnings per share of $0.93, for the nine months ended September 30, 2018. For the nine months ended September 30, 2019, normalized earnings attributable to common shareholders were $109 million, or $1.05 per share, compared with $84 million or $0.81 per share in the first nine months of 2018.

“Our financial results for the third quarter of 2019 were in line with management’s expectations,” said Brian Vaasjo, President and CEO of Capital Power. “The third quarter results benefitted from strong operating performance with average facility availability of 96 per cent. The Company

For immediate release October 28, 2019

2

captured an averaged realized Alberta power price of $59 per megawatt hour (MWh) in the third quarter that was 26% higher than the average spot power price of $47 per MWh that was impacted by cooler summer temperatures and low natural gas prices. We continue to have a positive outlook for Alberta power prices that is consistent with current forward prices of nearly $60 per MWh for 2020 and 2021.”

“With the recent acquisitions of Arlington Valley and Goreway and commercial operations of New Frontier Wind, the Company generated a record quarter of adjusted funds from operations of $225 million in the third quarter and $427 million in the first nine months of 2019. Based on our outlook for the remainder of the year, we continue to be on track to achieve AFFO at the top end of the $485 million to $535 million annual guidance range for 2019,” stated Mr. Vaasjo.

“One of the highlights in the third quarter was an agreement to acquire the remaining 50% share of Genesee 3 from TransAlta Corporation in exchange for the divestiture of our 50% share in Keephills 3 and $10 million cash,” continued Mr. Vaasjo. “The transaction closed on October 1 allowing us to assume full control of the Genesee site and providing us strategic freedom to make decisions that further optimize value for the Genesee units including accelerating dual-fuel capability to maximize flexibility in using natural gas as fuel. The non-cash net loss on the transaction is expected to be $227 million, including the $401 million impairment of Keephills 3 recorded in the third quarter, and expected offsetting gains in the fourth quarter upon close of the transaction of $174 million.”

The Company continued to be active with its Normal Course Issuer Bid (NCIB) by purchasing and cancelling 1.6 million common shares at an average exercise price of $30.40 per share for a total cost of $50 million in the third quarter. In the first nine months of 2019, the Company purchased and cancelled 2.0 million common shares at an average exercise price of $29.66 per share for a total cost of $60 million. Under its TSX approved NCIB, the Company can purchase and cancel up to 9.0 million common shares during the one-year period ending February 2020.

3

Operational and Financial Highlights 1

(unaudited)

Three months ended

September 30

Nine months ended

September 30

(millions of dollars except per share and operational amounts) 2019 2018 2019 2018

Electricity generation (Gigawatt hours) 6,808 5,213 18,090 14,823

Generation facility availability 96% 98% 95% 96%

Revenues and other income 3 $ 517 $ 395 $ 1,280 $ 1,077

Adjusted EBITDA 2, 3 $ 284 $ 179 $ 677 $ 565

Net (loss) income 3, 4, 5 $ (228) $ 17 $ (62) $ 122

Net (loss) income attributable to shareholders of the Company 3 $ (226) $ 18 $ (57) $ 127

Basic (loss) earnings per share 3 $ (2.25) $ 0.08 $ (0.90) $ 0.93

Diluted (loss) earnings per share 3 $ (2.25) $ 0.08 $ (0.90) $ 0.93

Normalized earnings attributable to common shareholders 2,3 $ 64 $ 34 $ 109 $ 84

Normalized earnings per share 2, 3 $ 0.60 $ 0.33 $ 1.05 $ 0.81

Net cash flows from operating activities $ 209 $ 65 $ 519 $ 317

Adjusted funds from operations 2 $ 225 $ 156 $ 427 $ 317

Adjusted funds from operations per share 2 $ 2.11 $ 1.52 $ 4.11 $ 3.07

Purchase of property, plant and equipment and other assets $ 193 $ 135 $ 523 $ 241

Dividends per common share, declared $ 0.4800 $ 0.4475 $ 1.3750 $ 1.2825

1 The operational and financial highlights in this press release should be read in conjunction with Management’s Discussion and Analysis and the unaudited condensed interim consolidated financial statements for the nine months ended September 30, 2019.

2 Earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation expense from its joint venture interests, gains or losses on disposals and unrealized changes in fair value of commodity derivatives and emissions credits (adjusted EBITDA), normalized earnings attributable to common shareholders, normalized earnings per share, adjusted funds from operations and adjusted funds from operations per share are non-GAAP financial measures and do not have standardized meanings under GAAP and are, therefore, unlikely to be comparable to similar measures used by other enterprises. See Non-GAAP Financial Measures.

3 Prior quarter amounts have been restated to reflect the IAS 8 accounting policy changes resulting from the transition to IFRS 16 – Leases.

4 Includes depreciation and amortization for the three months ended September 30, 2019 and 2018 of $135 million and $83 million respectively, and for the nine months ended September 30, 2019 and 2018 of $355 million and $250 million respectively. Forecasted depreciation and amortization for the three months ended December 31, 2019 is $117 million.

5 On June 28, 2019, as a result of the Alberta Government's Bill 3 - Job Creation Tax Cut Act, the Alberta corporate income tax rate was reduced from 12% to 8% over 4 years. Accordingly, the 2019 statutory tax rate is 26.5% and will decrease further to 25% for the 2020 year, to 24% for the 2021 year, and to 23% for the 2022 year. Due to this tax rate decrease, the Canadian deferred tax assets and liabilities were re-measured, resulting in the recognition of a deferred income tax recovery of $51 million within net income.

4

Significant Events

Genesee 3 and Keephills 3 swap transaction

On August 2, 2019, the Company announced it had entered into an agreement to divest its 50% share of Keephills 3 to TransAlta Corporation (TransAlta), and to acquire TransAlta’s 50% share of Genesee 3. The transaction closed on October 1, 2019, with a net cost to Capital Power of $10 million, subject to working capital and other closing adjustments. Previously both facilities had been owned and operated under 50/50 Joint Venture Agreements between Capital Power and TransAlta. Following the close of the transaction, Genesee 3 is fully owned and operated by Capital Power and Keephills 3 is fully owned and operated by TransAlta.

Keephills 3 and Genesee 3 are the only supercritical coal facilities in Alberta, with a net capacity of 463 MW and 466 MW, respectively. The swap of interests in the facilities is aligned with Capital Power’s strategic plan to deliver responsible energy for tomorrow. As a result of the transaction, the Company gained full control of the Genesee site, providing strategic freedom and latitude to make decisions that further optimize value for the Genesee units. The transaction is expected to streamline costs and commercial processes and reduce regulatory compliance risk.

The transaction results in an expected pre-tax net loss of approximately $227 million. In the third quarter of 2019, the Company recorded a pre-tax impairment of $401 million on Keephills 3 upon classification as assets held for sale. In the fourth quarter of 2019, the acquisition of the additional 50% of Genesee 3 will be accounted for as a business combination. A gain of approximately $60 million is expected to be recognized on the Company’s existing share of Genesee 3 as a result of the remeasurement of the carrying amount of the Company’s previously owned portion of Genesee 3. In addition, the net reduction to the carrying amounts of the Company’s coal-fired generation assets will result in a one-time adjustment of approximately $114 million to accelerate the recognition of deferred government grant revenue that aligns with the reduction in the new lower carrying amount of coal-fired assets. This relates to the government grant revenue that the Company is receiving over time from the province of Alberta for the 2029 phase-out of coal-fired generation. The Off-coal Agreement is not impacted by the transaction and as a result, compensation will continue to be collected over time and the Company’s ongoing obligations pertaining to the Off-coal Agreement are unchanged. The transaction is expected to be neutral to AFFO over the medium term.

Retirement plans announced for Brian Vaasjo, President and CEO

On July 29, 2019, the Company announced that Brian Vaasjo, President and Chief Executive Officer, has advised the Board of Directors of his intention to retire in 2020.

The announcement activated an established CEO succession plan developed by Capital Power’s Board of Directors. The Board’s search for a new President and Chief Executive Officer is well under way and the Board will announce a successor in due course. Mr. Vaasjo will continue in his current role, leading the Company and serving on the Board of Directors, until his successor assumes the role. For a period thereafter, Mr. Vaasjo will remain with the Company in an advisory role to support the Board, his successor, and the business and ensure a smooth leadership transition.

Dividend increase

On July 26, 2019, the Company’s Board of Directors approved an increase of 7.3% in the annual dividend for holders of its common shares, from $1.79 per common share to $1.92 per common share. This increased common share dividend will commence with the third quarter 2019 quarterly dividend payment on October 31, 2019 to shareholders of record at the close of business on September 30, 2019.

5

Accelerated plan for Genesee natural gas capability

On June 18, 2019, the Company announced that it is proceeding with a project that will maximize the flexibility to utilize natural gas as fuel at Genesee, which previously burned primarily coal. The financial impact of this transformation is highly dependant on carbon cost and natural gas price assumptions and is estimated to increase adjusted funds from operations by approximately $10 million in 2020 and $20 million in 2021.

The total cost of the project to completely transform Genesee 1 and 2 to dual-fuel capability and up to 40% gas capability for Genesee 3 is estimated at $50 million with expenditures of $18 million, $19 million, and $13 million in 2019 to 2021, respectively. The project involves adding new gas pipeline infrastructure within the Genesee site and modifications to the Genesee 1 and 2 boilers. The rated capacity of the units will remain the same.

After the units have been transformed to 100% dual-fuel capability, the units can utilize up to 100% natural gas or coal, or a mix of the two. The amount of coal used at any given time, versus natural gas, will be driven by several factors including natural gas and coal prices and carbon costs.

Based on Genesee 1 and 2 at 100% dual-fuel capability and Genesee 3 at 40% natural gas capability, annual greenhouse gas emissions (GHGs) are expected to be reduced by approximately 20% to 33%, assuming operation of the units is between 50% to 100% of hours on natural gas.

The coal operations at the Genesee facility are currently planned to continue up to December 2029, at which time regulatory requirements will require the Company to discontinue the use of coal. The Genesee facility will continue as a 100% natural gas-fired facility after that time. The Genesee units are already the most efficient coal generating units in Alberta and best performing from an emissions intensity perspective. Under the Genesee Performance Standard program, which commenced in 2016, a 10% improvement in efficiency and performance of the units is targeted by 2021, which improvements will benefit both natural gas and coal operations.

$325 million private placement debt financing

On June 12, 2019, the Company issued $325 million of private placement senior notes which consist of three tranches with 10, 12 and 15-year terms. The 10-year tranche has a principal amount of $210 million that matures in June 2029 with a coupon rate of 4.56%. The 12-year tranche has a $65 million principal amount and matures in June 2031 with a coupon rate of 4.72%. The 15-year tranche has a $50 million principal amount and matures in June 2034 with a coupon rate of 4.96%. The net proceeds from the transaction will primarily be used for refinancing of existing bank indebtedness and for other general corporate purposes.

Acquisition of the Goreway Power Station

On June 4, 2019, the Company completed the acquisition of 100% of the ownership interests in Goreway Power Station Holdings Inc., which owns the Goreway Power Station (Goreway). Goreway is an 875 MW natural gas combined cycle generation facility located in Brampton, Ontario. The purchase price consisted of (i) $410 million of total cash consideration, including working capital and other closing adjustments of $23 million, and (ii) the assumption of $590 million of project level debt.

Financing of the Goreway acquisition consisted of a combination of debt from the Company’s existing credit facilities and equity offerings as described below.

Goreway has a 20-year Accelerated Clean Energy Supply Contract expiring in June 2029 with the Ontario Independent Electricity System Operator (credit ratings of A (high)/Aa3 from DBRS and Moody’s, respectively). Goreway is strategically located in the Greater Toronto Area load centre making it an important asset in Ontario’s electric system and, in combination with the Company’s other Ontario natural gas assets, will provide operating and market synergies over time. The acquisition of Goreway supports the Company’s growth strategy and fully meets the Company’s investment criteria. In addition, the investment contributes to the Company’s dividend growth strategy through immediate AFFO accretion supported by contracted cash flows through mid-2029.

Goreway is expected to generate approximately $124 million of adjusted EBITDA and $50 million of AFFO in 2020. For the 2020-2023 period, average annual adjusted EBITDA and AFFO are estimated to be $127 million and $56 million, respectively. The acquisition of Goreway is forecasted to be $0.27 accretive to AFFO per share in 2020 representing growth of approximately 6%.

Preferred share offering

On May 16, 2019, the Company issued 6 million Cumulative Minimum Rate Reset Preference Shares, Series

6

11 (Series 11 Shares) at a price of $25.00 per share for gross proceeds of $150 million less issue costs of $4 million. The preferred shares will pay fixed cumulative dividends of $1.4375 per share per annum, yielding 5.75% per annum, payable on the last business day of March, June, September and December of each year, as and when declared by the Board of Directors of Capital Power, for the initial period ending June 30, 2024. The dividend rate will be reset on June 30, 2024 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.15%, provided that, in any event, such rate shall not be less than 5.75%. The Series 11 Shares are redeemable by Capital Power, at its option on June 30, 2024 and every five years thereafter at a value of $25.00 per share.

Holders of the Series 11 Shares will have the right to convert all or any part of their shares into Cumulative Floating Rate Preference Shares, Series 12 (Series 12 Shares), subject to certain conditions, on June 30, 2024 and every five years thereafter. Holders of the Series 12 Shares will be entitled to receive a cumulative quarterly floating dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 4.15%, as and when declared by the Board of Directors of Capital Power. The Series 12 Shares would be redeemable by Capital Power, at its option, on June 30, 2029 and June 30 of every fifth year thereafter at a value of $25.00 per share. The Series 12 Shares would also be redeemable by Capital Power, at its option, on any date after June 30, 2024 excluding June 30 of every fifth year, at a value of $25.50 per share.

Common share offering

In May of 2019, the Company completed a public offering of 4,945,000 subscription receipts (Subscription Receipts), on a bought deal basis, at an issue price of $30.30 per Subscription Receipt (the Offering Price), for total gross proceeds of $150 million less issue costs of $6 million (inclusive of the full exercise of a 645,000 over-allotment option). On June 4, 2019, upon closing of the Goreway acquisition, each Subscription Receipt was converted for one common share of the Company.

Capital Power increases its equity interest in C2CNT; testing of carbon nanotubes in concrete proceeding

In May 2019, Capital Power committed to increase its equity interest in C2CNT from 5% to 9% by March of 2020. C2CNT has developed an innovative technology that captures and transforms carbon dioxide into a useful and high-value product called carbon nanotubes (CNTs) which can be used as an additive to substantially increase the strength of materials such as concrete, steel and aluminum. Carbon dioxide emissions are avoided by reducing the amount of material required in addition to the carbon dioxide utilized in the production of CNTs.

Capital Power also has the right to provide notice to exercise two tranches of options in 2020 for an additional 31% equity interest in C2CNT. If exercised, Capital Power’s equity ownership of C2CNT would increase to a total of 40%.

The investment supports Capital Power’s pursuit of innovative and leading-edge technology to reduce greenhouse gases. The carbon conversion technology, led by Dr. Stuart Licht, head of the C2CNT team and professor of chemistry at George Washington University, is currently being tested at demonstration scale at the Alberta Carbon Conversion Technology Centre located at the Shepard Energy Centre in Calgary that Capital Power co-owns with ENMAX.

Lehigh Hanson (Lehigh), a subsidiary of HeidelbergCement A.G., a worldwide construction materials company, has agreed to conduct testing for the utilization of CNTs in concrete at their cost. The testing is expected in the fall of 2019 followed by limited marketing of the CNTs in concrete product in the first half of 2020. Lehigh has also made a modest financial contribution to C2CNT development.

Additional information on C2CNT is available on Capital Power’s website at: https://www.capitalpower.com/sustainability/innovation.

Appointments to the Board of Directors

Effective April 26, 2019, Robert Phillips was appointed to the Capital Power Board of Directors.

Effective March 1, 2019, Jane Peverett was appointed to the Capital Power Board of Directors.

Heat rate call option at Arlington Valley

During the first quarter of 2019, the Company entered into a heat rate call option agreement (HRCO) with an investment grade counterparty covering the periods outside of Arlington Valley’s existing summer tolling agreements. The HRCO commenced on April 1, 2019 and terminates December 31, 2025, covering (i) April

https://www.capitalpower.com/sustainability/innovation/


7

and November-December 2019 and (ii) January-May and October-December 2020-2025. Pursuant to the HRCO the counterparty has the right to call the plant in exchange for fixed monthly premiums plus reimbursements for fuel at an indexed price, variable operating and maintenance expense and start charges. Adjusted EBITDA and AFFO from the Arlington Valley facility during the period covered by the HRCO is expected to be consistent with the guidance provided at the time the acquisition was announced.

Analyst conference call and webcast

Capital Power will be hosting a conference call and live webcast with analysts on October 28, 2019 at 9:00 am (MDT) to discuss the third quarter operating and financial results. The conference call dial-in numbers are:

(604) 638-5340 (Vancouver) (403) 351-0324 (Calgary) (416) 915-3239 (Toronto) (514) 375-0364 (Montreal) (800) 319-4610 (toll-free from Canada and USA)

Interested parties may also access the live webcast on the Company’s website at www.capitalpower.com with an archive of the webcast available following the conclusion of the analyst conference call.

Non-GAAP Financial Measures

The Company uses (i) earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation expense from its joint venture interests, gains or losses on disposals and unrealized changes in fair value of commodity derivatives and emission credits (adjusted EBITDA), (ii) adjusted funds from operations, (iii) adjusted funds from operations per share (iv) normalized earnings attributable to common shareholders, and (v) normalized earnings per share as financial performance measures. These terms are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures should not be considered alternatives to net income, net income attributable to shareholders of the Company, net cash flows from operating activities or other measures of financial performance calculated in accordance with GAAP. Rather, these measures are provided to complement GAAP measures in the analysis of the Company’s results of operations from management’s perspective. Adjusted EBITDA

Capital Power uses adjusted EBITDA to measure the operating performance of facilities and categories of facilities from period to period. Management believes that a measure of facility operating performance is more meaningful if results not related to facility operations such as impairments, foreign exchange gains or losses and gains or losses on disposals are excluded from the adjusted EBITDA measure. Commencing with the Company’s March 31, 2019 quarter-end, adjusted EBITDA excludes unrealized changes in fair value of commodity derivatives and emission credits which were previously included in adjusted EBITDA. This change was made to better align the Company’s measure of adjusted EBITDA with its other non-GAAP measures, as both the adjusted funds from operations and the normalized earnings per share measures exclude the impacts of unrealized changes in fair value of commodity derivatives and emission credits. This change also results in improved period over period comparability of adjusted EBITDA. Comparative figures have been restated to reflect the above change to the adjusted EBITDA metric.

http://www.capitalpower.com/

http://www.capitalpower.com/

8

A reconciliation of adjusted EBITDA to net income is as follows:

(unaudited, $ millions) Three months ended

Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017

Revenues and other income 2 517 366 397 340 395 369 313 267

Energy purchases and fuel, other raw materials and operating charges, staff costs and employee benefits expense, and other administrative expense (231) (134) (167) (233) (261) (152) (153) (125)

Remove unrealized changes in fair value of commodity derivatives and emission credits included within revenues and energy purchases and fuel (8) (48) (34) 53 35 (22) 1 18

Adjusted EBITDA from joint ventures 1 6 7 6 11 10 12 18 18

Adjusted EBITDA 284 191 202 171 179 207 179 178

Depreciation and amortization 2 (135) (122) (98) (85) (83) (83) (84) (80)

Unrealized changes in fair value of commodity derivatives and emission credits 8 48 34 (53) (35) 22 (1) (18)

Impairment (401) - - - - - - -

Gain on disposal of joint venture - - - 159 - - - -

Foreign exchange (loss) gain (1) - (4) 6 (2) 3 3 (4)

Net finance expense (42) (37) (36) (33) (28) (29) (33) (32)

Finance expense and depreciation

expense from joint ventures 1 (7) (7) (8) (10) (7) (8) (7) (13)

Income tax recovery (expense) 2 66 33 (30) (19) (7) (46) (18) (45)

Net (loss) income (228) 106 60 136 17 66 39 (14)

Net (loss) income attributable to:

Non-controlling interests (2) (2) (1) (2) (1) (2) (2) (3)

Shareholders of the Company 2 (226) 108 61 138 18 68 41 (11)

Net (loss) income (228) 106 60 136 17 66 39 (14)

1 Total income from joint ventures as per the Company’s consolidated statements of income (loss). Prior quarters’ values include Capital Power’s share of K2 Wind up until December 31, 2018 disposal date.

2 Prior quarters’ amounts have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16.

Adjusted funds from operations and adjusted funds from operations per share

The Company uses adjusted funds from operations as a measure of the Company’s ability to generate cash from its current operating activities to fund growth capital expenditures, debt repayments and common share dividends to the Company’s shareholders.

Adjusted funds from operations represents net cash flows from operating activities adjusted to include net finance expense and current income tax expense and exclude changes in operating working capital and distributions received from the Company’s joint venture interests. Net finance expense and current income tax expense are included as the timing of cash receipts and payments of interest and income taxes and the resulting cash basis amounts are not comparable from period to period. Changes in operating working capital are excluded from adjusted funds from operations as the timing of cash receipts and payments also affects the period-to-period comparability. Distributions received from the Company’s joint venture interests are excluded as the distributions are calculated after the effect of joint venture debt payments, which are not considered operating activities. Adjusted funds from operations is reduced by the tax equity financing project investors’ shares of adjusted funds from operations associated with assets under tax equity financing structures to ensure that only the Company’s share is reflected in the overall metric. Adjusted funds from operations also excludes the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to the Company’s bank margin account held with a specific exchange counterparty. Adjusted funds from operations is reduced by sustaining capital expenditures and preferred share dividends and adjusted to include the Company’s share of the adjusted funds from operations of its joint venture interests and cash from coal compensation that will be received annually.

9

Adjusted funds from operations per share is determined by applying adjusted funds from operations to the weighted average number of common shares used in the calculation of basic, diluted and normalized earnings per share.

A reconciliation of net cash flows from operating activities to adjusted funds from operations is as follows:


September 30

Nine months ended September

30

2019 2018 2019 2018

Net cash flows from operating activities per condensed interim consolidated statements of cash flows 209 65 519 317

Add (deduct) items included in calculation of net cash flows from operating activities per condensed interim consolidated statements of cash flows:

Interest paid 36 20 83 70

Realized loss on settlement of interest rate derivatives - - 19 -

Change in fair value of derivatives reflected as cash settlement 1 4 (36) (16)

Distributions received from joint ventures (3) (5) (9) (24)

Miscellaneous financing charges paid 1 1 1 4 4

Income taxes paid 2 1 4 2

Change in non-cash operating working capital (3) 68 (26) 62

34 89 39 98

Net finance expense 2 (33) (23) (90) (72)

Current income tax expense 3 (6) (6) (7) (15)

Sustaining capital expenditures 4 (18) (13) (58) (54)

Preferred share dividends paid (13) (10) (36) (30)

Cash received from coal compensation 50 50 50 50

Remove tax equity interests’ respective shares of adjusted funds from operations (2) (1) (4) (5)

Adjusted funds from operations from joint ventures 4 5 14 28

Adjusted funds from operations 225 156 427 317

Weighted average number of common shares outstanding (millions) 106.5 102.4 104.0 103.2

Adjusted funds from operations per share ($) 2.11 1.52 4.11 3.07

1 Included in other cash items on the condensed interim consolidated statement of cash flows to reconcile net income to net cash flows from operating activities.

2 Excludes unrealized changes on interest rate derivative contracts, amortization, accretion charges and non-cash implicit interest on tax equity investment structures.

3 Excludes current income tax expense related to the disposal of the Company’s interest in K2 Wind joint venture as the amount is considered an investing activity.

4 Includes sustaining capital expenditures net of partner contributions of $2 million and $5 million for the three and nine months ended

September 30, 2019, respectively, compared with $1 million and $6 million for the three and nine months ended September 30,

2018.

10

Normalized earnings attributable to common shareholders and normalized earnings per share

The Company uses normalized earnings attributable to common shareholders and normalized earnings per share to measure performance by period on a comparable basis. Normalized earnings per share is based on earnings (loss) used in the calculation of basic earnings (loss) per share according to GAAP and adjusted for items that are not reflective of performance in the period such as unrealized fair value changes, impairment charges, unusual tax adjustments, gains and losses on disposal of assets or unusual contracts, and foreign exchange gain or loss on the revaluation of U.S. dollar denominated debt. The adjustments, shown net of tax, consist of unrealized fair value changes on financial instruments that are not necessarily indicative of future actual realized gains or losses, non-recurring gains or losses, or gains or losses reflecting corporate structure decisions.

(unaudited, $ millions except per share amounts and number of common shares) Three months ended

Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017

Basic (loss) earnings per share ($)2 (2.25) 0.93 0.49 1.24 0.08 0.55 0.30 (0.21)

Net (loss) income attributable to shareholders of the Company per condensed interim consolidated statements of (loss) income 2 (226) 108 61 138 18 68 41 (11)

Preferred share dividends including Part VI.1 tax (14) (12) (11) (11) (10) (11) (10) (11)

(Loss) earnings attributable to common shareholders 2 (240) 96 50 127 8 57 31 (22)

Unrealized changes in fair value of derivatives 1 (3) (30) (20) 35 26 (19) 25 14

Impairment (see Significant Events) 307 - - - - - - -

Alberta tax rate change - (51) - - - - - -

Gain on disposal of joint venture - - - (134) - - - -

Non-cash tax equity adjustment - - - - - (15) - -

Realized foreign exchange gain on settlement of foreign currency derivative instruments - - - - - - (29) -

Asset held for sale accounting treatment of K2 Wind - - - 3 - - - -

Income tax adjustments - - - - - (2) 2 -

Unrealized foreign exchange gain on revaluation of U.S. dollar denominated debt - - - - - - - (1)

Realized foreign exchange gain on revaluation of U.S. dollar denominated debt - - - - - - - (1)

Provision for Line Loss Rule Proceeding - - - - - - - 7

U.S. tax reform rate decrease - - - - - - - 31

Success fee received related to development project - - - - - - - (3)

Release of tax liability on foreign domiciled investment - - - - - - - (1)

Normalized earnings attributable to common shareholders 2 64 15 30 31 34 21 29 24

Weighted average number of common shares outstanding (millions) 106.5 103.6 101.8 102.3 102.4 103.1 104.2 104.3

Normalized earnings per share ($)2 0.60 0.14 0.29 0.30 0.33 0.20 0.28 0.23

1 Includes impacts of the interest rate non-hedge held by one of the Company’s joint ventures and recorded within income from joint ventures on the Company’s statements of income.

2 Prior quarters’ amounts have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16.

11

Forward-looking Information

Forward-looking information or statements included in this press release are provided to inform the Company’s shareholders and potential investors about management’s assessment of Capital Power’s future plans and operations. This information may not be appropriate for other purposes. The forward-looking information in this press release is generally identified by words such as will, anticipate, believe, plan, intend, target, and expect or similar words that suggest future outcomes.

Material forward-looking information in this press release includes disclosures regarding: (i) expected expenditures and impacts related to the Genesee dual-fuel project including expected AFFO increases, (ii) expected benefits, including AFFO impacts, related to the swap of interests in the Genesee 3 and Keephills 3 facilities, (iii) expected benefits, including AFFO and AFFO per share increases, related to the acquisition of Goreway, (iv) expected impacts on adjusted EBITDA and AFFO from Arlington Valley driven by the HRCO signed in the year, (v) expected AFFO performance compared to guidance for 2019 and (vi) forecasted depreciation and amortization for the remainder of 2019.

These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements relate to: (i) electricity, other energy and carbon prices, (ii) performance, (iii) status of and impact of policy, legislation and regulations, and (iv) effective tax rates.

Whether actual results, performance or achievements will conform to the Company’s expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from the Company’s expectations. Such material risks and uncertainties are: (i) changes in electricity prices in markets in which the Company operates, (ii) changes in energy commodity market prices and use of derivatives, (iii) regulatory and political environments including changes to environmental, financial reporting, market structure and tax legislation, (iv) generation facility availability and performance including maintenance of equipment, (v) ability to fund current and future capital and working capital needs, (vi) changes in market prices and availability of fuel, and (vii) ability to realize the anticipated benefits of the Goreway acquisition, (viii) limitations inherent in the Company’s review of acquired assets, (ix) ability to realize the anticipated benefits of the swap of interests in the Genesee 3 and Keephills 3 facilities, and (x) changes in general economic and competitive conditions. See Risks and Risk Management in the Company’s Management’s Discussion and Analysis for the year ended December 31, 2018, prepared as of February 15, 2019, for further discussion of these and other risks.

Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of the specified approval date. The Company does not undertake or accept any obligation or undertaking to release publicly any updates or revisions to any forward-looking statements to reflect any change in the Company’s expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law.

For more information, please contact:

Media Relations: Katherine Perron (780) 392-5335 [email protected]

Investor Relations: Randy Mah (780) 392-5305 or (866) 896-4636 (toll-free) [email protected]

Capital Power Corporation Management’s Discussion and Analysis Q3-2019 12

CAPITAL POWER CORPORATION

Management’s Discussion and Analysis

This management’s discussion and analysis (MD&A), prepared as of October 25, 2019, should be read in conjunction with the unaudited condensed interim consolidated financial statements of Capital Power Corporation and its subsidiaries for the nine months ended September 30, 2019, the audited consolidated financial statements and MD&A of Capital Power Corporation for the year ended December 31, 2018, the annual information form of Capital Power Corporation dated February 19, 2019, and the cautionary statements regarding forward-looking information which begin on page 13. In this MD&A, any reference to the Company or Capital Power, except where otherwise noted or the context otherwise indicates, means Capital Power Corporation together with its subsidiaries.

In this MD&A, financial information for the nine months ended September 30, 2019 and the nine months ended September 30, 2018 is based on the unaudited condensed interim consolidated financial statements of the Company for such periods which were prepared in accordance with Canadian generally accepted accounting principles (GAAP) and are presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company’s Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. The Board of Directors approved this MD&A as of October 25, 2019.

Contents

Forward-looking Information ........................................................................................................................................ 13 Overview of Business and Corporate Structure ........................................................................................................... 14 Corporate Strategy ...................................................................................................................................................... 14 Performance Overview ................................................................................................................................................ 14 Outlook ........................................................................................................................................................................ 15 Non-GAAP Financial Measures ................................................................................................................................... 16 Financial Highlights ...................................................................................................................................................... 20 Significant Events ........................................................................................................................................................ 21 Consolidated Net Income (Loss) and Results of Operations ....................................................................................... 24 Comprehensive (Loss) Income .................................................................................................................................... 31 Financial Position ......................................................................................................................................................... 32 Liquidity and Capital Resources .................................................................................................................................. 33 Contingent Liabilities and Provisions ........................................................................................................................... 36 Risks and Risk Management ....................................................................................................................................... 37 Environmental Matters ................................................................................................................................................. 37 Regulatory Matters ...................................................................................................................................................... 37 Use of Judgments and Estimates ................................................................................................................................ 37 Accounting Changes .................................................................................................................................................... 38 Financial Instruments ................................................................................................................................................... 40 Disclosure Controls and Procedures and Internal Control over Financial Reporting ................................................... 41 Summary of Quarterly Results ..................................................................................................................................... 42 Share and Partnership Unit Information ....................................................................................................................... 47 Additional Information .................................................................................................................................................. 47


FORWARD-LOOKING INFORMATION

Forward-looking information or statements included in this MD&A are provided to inform the Company’s shareholders and potential investors about management’s assessment of Capital Power’s future plans and operations. This information may not be appropriate for other purposes. The forward-looking information in this MD&A is generally identified by words such as will, anticipate, believe, plan, intend, target, and expect or similar words that suggest future outcomes.

Material forward-looking information in this MD&A includes expectations regarding:

• future revenues, expenses, earnings and adjusted funds from operations,

• the future pricing of electricity and market fundamentals in existing and target markets,

• future dividend growth,

• the Company’s future cash requirements including interest and principal repayments, capital expenditures, dividends and distributions,

• the Company’s sources of funding, adequacy and availability of committed bank credit facilities and future borrowings,

• future growth and emerging opportunities in the Company’s target markets including the focus on certain technologies,

• the timing of, funding of, and costs for existing, planned and potential development projects and acquisitions (including phase 1 of the Whitla Wind project and the Cardinal Point Wind project),

• facility availability and planned outages,

• capital expenditures for facility maintenance and other (sustaining capital, future growth projects, Genesee dual-fuel capability project),

• the impact of market designs in the Company’s core markets,

• the impact of the transformation of the Genesee units to 100% dual-fuel,

• expectations pertaining to the financial impacts of the acquisition of Goreway (see Significant Events), including the impacts to adjusted funds from operations, adjusted funds from operations per share and adjusted EBITDA,

• expectations pertaining to the financial impacts of the swap of interests in the Genesee 3 and Keephills 3 facilities (see Significant Events), including expectations regarding the impacts to adjusted funds from operations and the expected accounting impacts of the transaction including the pre-tax net loss on the transaction, and

• expectations around the Line Loss Rule Proceeding including timing of retrospective loss factors being finalized, participation in applicable appeal processes, and potential impacts to the Company.

These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes are appropriate including its review of purchased businesses and assets. The material factors and assumptions used to develop these forward-looking statements relate to:

• electricity and other energy prices and carbon prices,

• performance,

• business prospects (including potential re-contracting of facilities) and opportunities including expected growth and capital projects,

• status of and impact of policy, legislation and regulations,

• effective tax rates,

• other matters discussed under the Performance Overview and Outlook sections,

• anticipated performance of the acquired Goreway facility (see Significant Events), and

• the anticipated future performance of the Genesee 3 and Keephills 3 facilities used to assess the financial impacts of the swap of interests (see Significant Events).

Whether actual results, performance or achievements will conform to the Company’s expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from the Company’s expectations. Such material risks and uncertainties are:

• changes in electricity prices in markets in which the Company operates,

• changes in energy commodity market prices and use of derivatives,

• regulatory and political environments including changes to environmental, financial reporting, market structure and tax legislation,

• generation facility availability and performance including maintenance of equipment,

• ability to fund current and future capital and working capital needs,

• acquisitions and developments including timing and costs of regulatory approvals and construction,

• changes in market prices and availability of fuel,

• ability to realize the anticipated benefits of the Goreway acquisition,

• ability to realize the anticipated benefits of the swap of interests in the Genesee 3 and Keephills 3 facilities,


• limitations inherent in the Company’s review of acquired assets, and

• changes in general economic and competitive conditions.

See Risks and Risk Management in the Company’s December 31, 2018 annual MD&A for further discussion of these and other risks.

Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of

the specified approval date. The Company does not undertake or accept any obligation or undertaking to release

publicly any updates or revisions to any forward-looking statements to reflect any change in the Company’s

expectations or any change in events, conditions or circumstances on which any such statement is based, except as

required by law.

OVERVIEW OF BUSINESS AND CORPORATE STRUCTURE

Capital Power is a growth-oriented North American power producer headquartered in Edmonton, Alberta. The Company develops, acquires, owns and operates power generation facilities using a variety of energy sources. Capital Power owns nearly 6,000 megawatts (MW) of power generation capacity at 25 facilities across North America. Approximately 900 MW of owned generation capacity is in advanced development in Alberta and Illinois.

The Company’s power generation operations and assets are owned by Capital Power L.P. (CPLP), Capital Power L.P. Holdings Inc., and Capital Power (US Holdings) Inc., all wholly owned subsidiaries of the Company.

CORPORATE STRATEGY

The Company’s corporate strategy remains unchanged from that disclosed in its 2018 annual MD&A.

PERFORMANCE OVERVIEW

The Company measures its performance in relation to its corporate strategy through financial and non-financial targets that are approved by the Board of Directors of Capital Power. The measurement categories include corporate measures and measures specific to certain groups within the Company. The corporate measures are company-wide and include adjusted funds from operations and safety. The group-specific measures include facility operating margin and other operations measures, committed capital, construction and maintenance capital on budget and on schedule, and facility site safety.

Operational excellence

Performance measure 2019 target

Actual results for the nine months ended September 30, 2019

Facility availability average 95% or greater 95%

Sustaining capital expenditures $80 to 90 million $58 million 1

1 Includes sustaining capital expenditures net of joint venture contributions of $5 million.

The Company’s facility availability averaged 95% which reflected planned outages at Genesee, Cloverbar Energy Centre, Roxboro, Southport, Decatur Energy, Shepard, Arlington Valley, Joffre, and Goreway. Unplanned outages also occurred at Genesee, Shepard, EnPower, Cloverbar Energy Centre, and Southport.

Sustaining capital expenditures for the nine months ended September 30, 2019 were lower than target for the year to date primarily due to timing of sustaining capital projects which were budgeted in the first nine months of the year but are now expected to occur later in the year. Full year sustaining capital expenditures are expected to be consistent with the target.


Disciplined growth

Performance measure 2019 target Status as at September 30, 2019

Whitla Wind Completion of Whitla Wind on budget and on time for commercial operations in December 2019.

Construction expected to be complete in the fourth quarter of 2019. Total project costs are expected to exceed the budget due largely to foreign exchange impacts (see Liquidity and Capital Resources).

Cardinal Point Wind Progress on the development of Cardinal Point Wind to be on track with budget and the March 2020 completion date.

Construction expected to be complete and on budget in the first quarter of 2020.

Other contracted growth $500 million of committed capital. The Company exceeded its target for other contracted growth through the acquisition of Goreway (see Significant Events).

Financial stability and strength

Performance measure 2019 target 1

Actual results for the nine months ended September 30, 2019

Adjusted funds from operations 2 $485 million to $535 million $427 million

Adjusted EBITDA 2 $870 million to $920 million $677 million

1 The targets presented at the Company’s Investor Day in December 2018 were revised to include the expected impact of the acquisition of Goreway for the periods subsequent to the close of the transaction (see Significant Events).

2 Adjusted funds from operations and adjusted EBITDA are non-GAAP financial measures. See Non-GAAP Financial Measures.

OUTLOOK

The following discussion should be read in conjunction with the Forward-looking Information section of this MD&A which identifies the material factors and assumptions used to develop forward-looking information and their material associated risk factors.

At its Investor Day held in December 2018, the Company provided financial guidance for 2019 adjusted funds from operations in the range of $460 million to $510 million and 2019 adjusted EBITDA in the range of $800 million to $850 million (see Non-GAAP Financial Measures). These ranges were subsequently revised as a result of the acquisition of Goreway (see Significant Events) to be $485 million to $535 million for adjusted funds from operations and $870 million to $920 million for adjusted EBITDA, which includes the expected results of the acquired assets subsequent to transaction close. Based on the actual results for the first nine months of 2019 and the Company’s forecast for the remainder of 2019, the Company expects adjusted funds from operations for 2019 to be at the top end of the adjusted guidance range.

Priorities for the Company in 2019 include working with provincial and federal governments and relevant agencies on the evolution of energy markets, specifically in Alberta and Ontario, and the design and implementation of climate policy. The Company continues to develop its wind facilities with Whitla Wind and Cardinal Point Wind expected to commence commercial operation in the fourth quarter of 2019 and the first quarter of 2020, respectively. The Company has exceeded its $500 million target for additional committed capital in 2019 with the acquisition of Goreway (see Significant Events). Finalizing the integration of Goreway will be a priority during the remainder of 2019.

In 2019, Capital Power’s availability target of 95% reflects major scheduled maintenance outages for Genesee 1, Clover Bar Energy Centre, Joffre, Shepard, and Decatur Energy compared to those scheduled for Genesee 2, Genesee 3, Clover Bar Energy Centre, Joffre, Shepard, East Windsor, and Decatur Energy in 2018.

The Alberta portfolio position, contracted prices and forward Alberta pool prices for 2020, 2021, and 2022 as at September 30, 2019, were:

Alberta commercial portfolio positions and power prices Full year 2020 Full year 2021 Full year 2022

Percentage of baseload generation sold forward 1 53% 2% 10%

Contracted price 2 Mid-$50 High-$60 Low-$50

Forward Alberta pool prices $57 $58 $55

1 Based on the Alberta baseload facilities plus a portion of Joffre and the uncontracted portion of Shepard.

2 Forecasted average contracted prices may differ significantly from future average realized prices as future realized prices are driven by a combination of previously contracted prices and settled prices.


The 2019 targets and forecasts are based on numerous assumptions including power and natural gas price forecasts. However, they do not include the effects of potential future acquisitions or development activities, or potential market and operational impacts relating to unplanned facility outages including outages at facilities of other market participants, and the related impacts on market power prices.

At its Investor Day held in December 2018, the Company extended the 7% annual dividend growth guidance for one additional year to 2021. Each annual increase is subject to changing circumstances and approval by the Board of Directors of Capital Power at the time of the increase.

See Liquidity and Capital Resources for discussion of future cash requirements and expected sources of funding. It is expected that, outside of new growth opportunities, no additional common share equity will be required during the remainder of 2019.

NON-GAAP FINANCIAL MEASURES

The Company uses (i) earnings before net finance expense, income tax expense, depreciation and amortization, impairments, foreign exchange gains or losses, finance expense and depreciation expense from its joint venture interests, gains or losses on disposals and unrealized changes in fair value of commodity derivatives and emission credits (adjusted EBITDA), (ii) adjusted funds from operations, (iii) adjusted funds from operations per share, (iv) normalized earnings attributable to common shareholders, and (v) normalized earnings per share as financial performance measures.

These terms are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures should not be considered alternatives to net income, net income attributable to shareholders of the Company, net cash flows from operating activities or other measures of financial performance calculated in accordance with GAAP. Rather, these measures are provided to complement GAAP measures in the analysis of the Company’s results of operations from management’s perspective.

Adjusted EBITDA

Capital Power uses adjusted EBITDA to measure the operating performance of facilities and categories of facilities from period to period. Management believes that a measure of facility operating performance is more meaningful if results not related to facility operations such as impairments, foreign exchange gains or losses and gains or losses on disposals are excluded from the adjusted EBITDA measure. Commencing with the Company’s March 31, 2019 quarter-end, adjusted EBITDA excludes unrealized changes in fair value of commodity derivatives and emission credits which were previously included in adjusted EBITDA. This change was made to better align the Company’s measure of adjusted EBITDA with its other non-GAAP measures, as both the adjusted funds from operations and the normalized earnings per share measures exclude the impacts of unrealized changes in fair value of commodity derivatives and emission credits. This change also results in improved period over period comparability of adjusted EBITDA.

Comparative figures have been restated to reflect the above change to the adjusted EBITDA metric.


A reconciliation of adjusted EBITDA to net income is as follows:


Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017


Energy purchases and fuel, other raw materials and operating charges, staff costs and employee benefits expense, and other administrative expense (231) (134) (167) (233) (261) (152) (153) (125)

Remove unrealized changes in fair value of commodity derivatives and emission credits included within revenues and energy purchases and fuel (8) (48) (34) 53 35 (22) 1 18

Adjusted EBITDA from joint ventures 1 6 7 6 11 10 12 18 18

Adjusted EBITDA 284 191 202 171 179 207 179 178

Depreciation and amortization 2 (135) (122) (98) (85) (83) (83) (84) (80)

Unrealized changes in fair value of commodity derivatives and emission credits 8 48 34 (53) (35) 22 (1) (18)

Impairment (401) - - - - - - -

Gain on disposal of joint venture - - - 159 - - - -

Foreign exchange (loss) gain (1) - (4) 6 (2) 3 3 (4)

Net finance expense (42) (37) (36) (33) (28) (29) (33) (32)

Finance expense and depreciation

expense from joint ventures 1 (7) (7) (8) (10) (7) (8) (7) (13)

Income tax recovery (expense) 2 66 33 (30) (19) (7) (46) (18) (45)

Net (loss) income (228) 106 60 136 17 66 39 (14)

Net (loss) income attributable to:

Non-controlling interests (2) (2) (1) (2) (1) (2) (2) (3)

Shareholders of the Company 2 (226) 108 61 138 18 68 41 (11)

Net (loss) income (228) 106 60 136 17 66 39 (14)

1 Total income from joint ventures as per the Company’s consolidated statements of income (loss). Prior quarters’ values include Capital Power’s share of K2 Wind up until the December 31, 2018 disposal date.

2 Prior quarters’ amounts have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16, see Accounting Changes.

Adjusted funds from operations and adjusted funds from operations per share

The Company uses adjusted funds from operations as a measure of the Company’s ability to generate cash from its current operating activities to fund growth capital expenditures, debt repayments and common share dividends to the Company’s shareholders.

Adjusted funds from operations represents net cash flows from operating activities adjusted to include net finance expense and current income tax expense and exclude changes in operating working capital and distributions received from the Company’s joint venture interests. Net finance expense and current income tax expense are included as the timing of cash receipts and payments of interest and income taxes and the resulting cash basis amounts are not comparable from period to period. Changes in operating working capital are excluded from adjusted funds from operations as the timing of cash receipts and payments also affects the period-to-period comparability. Distributions received from the Company’s joint venture interests are excluded as the distributions are calculated after the effect of joint venture debt payments, which are not considered operating activities. Adjusted funds from operations is reduced by the tax equity financing project investors’ shares of adjusted funds from operations associated with assets under tax equity financing structures to ensure that only the Company’s share is reflected in the overall metric. Adjusted funds from operations also excludes the impact of fair value changes in certain unsettled derivative financial instruments that are charged or credited to the Company’s bank margin account held with a specific exchange counterparty. Adjusted funds from operations is reduced by sustaining capital expenditures and preferred share dividends and adjusted to include the Company’s share of the adjusted funds from operations of its joint venture interests and cash from coal compensation that will be received annually.

Adjusted funds from operations per share is determined by applying adjusted funds from operations to the weighted average number of common shares used in the calculation of basic, diluted and normalized earnings per share.


A reconciliation of net cash flows from operating activities to adjusted funds from operations is as follows:

(unaudited, $ millions) Three months ended September 30

Nine months ended September 30

2019 2018 2019 2018

Net cash flows from operating activities per condensed interim consolidated statements of cash flows 209 65 519 317

Add (deduct) items included in calculation of net cash flows from operating activities per condensed interim consolidated statements of cash flows:

Interest paid 36 20 83 70

Realized loss on settlement of interest rate derivatives - - 19 -

Change in fair value of derivatives reflected as cash settlement 1 4 (36) (16)

Distributions received from joint ventures (3) (5) (9) (24)

Miscellaneous financing charges paid 1 1 1 4 4

Income taxes paid 2 1 4 2

Change in non-cash operating working capital (3) 68 (26) 62

34 89 39 98

Net finance expense 2 (33) (23) (90) (72)

Current income tax expense 3 (6) (6) (7) (15)

Sustaining capital expenditures 4 (18) (13) (58) (54)

Preferred share dividends paid (13) (10) (36) (30)

Cash received from coal compensation 50 50 50 50

Remove tax equity interests’ respective shares of adjusted funds from operations (2) (1) (4) (5)

Adjusted funds from operations from joint ventures 4 5 14 28

Adjusted funds from operations 225 156 427 317

Weighted average number of common shares outstanding (millions) 106.5 102.4 104.0 103.2

Adjusted funds from operations per share ($) 2.11 1.52 4.11 3.07

1 Included in other cash items on the condensed interim consolidated statements of cash flows to reconcile net income to net cash flows from operating activities.

2 Excludes unrealized changes on interest rate derivative contracts, amortization, accretion charges and non-cash implicit interest on tax equity investment structures.

3 Excludes current income tax expense related to the disposal of the Company’s interest in the K2 Wind joint venture as the amount is considered an investing activity.

4 Includes sustaining capital expenditures net of partner contributions of $2 million and $5 million for the three and nine months ended September 30, 2019, respectively, compared with $1 million and $6 million for the three and nine months ended September 30, 2018, respectively.


Normalized earnings attributable to common shareholders and normalized earnings per share

The Company uses normalized earnings attributable to common shareholders and normalized earnings per share to measure performance by period on a comparable basis. Normalized earnings per share is based on earnings (loss) used in the calculation of basic earnings (loss) per share according to GAAP and adjusted for items that are not reflective of performance in the period such as unrealized fair value changes, impairment charges, unusual tax adjustments, gains and losses on disposal of assets or unusual contracts, and foreign exchange gain or loss on the revaluation of U.S. dollar denominated debt. The adjustments, shown net of tax, consist of unrealized fair value changes on financial instruments that are not necessarily indicative of future actual realized gains or losses, non-recurring gains or losses, or gains or losses reflecting corporate structure decisions.

(unaudited, $ millions except per share amounts and number of common shares) Three months ended

Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017

Basic (loss) earnings per share ($)2 (2.25) 0.93 0.49 1.24 0.08 0.55 0.30 (0.21)

Net (loss) income attributable to shareholders of the Company per condensed interim consolidated statements of (loss) income 2 (226) 108 61 138 18 68 41 (11)

Preferred share dividends including Part VI.1 tax (14) (12) (11) (11) (10) (11) (10) (11)

(Loss) earnings attributable to common shareholders 2 (240) 96 50 127 8 57 31 (22)

Unrealized changes in fair value of derivatives 1 (3) (30) (20) 35 26 (19) 25 14

Impairment (see Significant Events) 307 - - - - - - -

Alberta tax rate change - (51) - - - - - -

Gain on disposal of joint venture - - - (134) - - - -

Non-cash tax equity adjustment - - - - - (15) - -

Realized foreign exchange gain on settlement of foreign currency derivative instruments - - - - - - (29) -

Asset held for sale accounting treatment of K2 Wind - - - 3 - - - -

Income tax adjustments - - - - - (2) 2 -

Unrealized foreign exchange gain on revaluation of U.S. dollar denominated debt - - - - - - - (1)

Realized foreign exchange gain on revaluation of U.S. dollar denominated debt - - - - - - - (1)

Provision for Line Loss Rule Proceeding - - - - - - - 7

U.S. tax reform rate decrease - - - - - - - 31

Success fee received related to development project - - - - - - - (3)

Release of tax liability on foreign domiciled investment - - - - - - - (1)

Normalized earnings attributable to common shareholders 2 64 15 30 31 34 21 29 24

Weighted average number of common shares outstanding (millions) 106.5 103.6 101.8 102.3 102.4 103.1 104.2 104.3

Normalized earnings per share ($)2 0.60 0.14 0.29 0.30 0.33 0.20 0.28 0.23

1 Includes impacts of the interest rate non-hedge held by one of the Company’s joint ventures and recorded within income from joint ventures on the Company’s statements of income.


Normalized earnings per share reflects the period-over-period change in normalized earnings attributable to common shareholders and the changes from period to period in the weighted average number of common shares outstanding.


FINANCIAL HIGHLIGHTS

(unaudited, $ millions, except per share amounts) Three months ended September 30


2019 2018 2019 2018

Revenues and other income 3 517 395 1,280 1,077

Adjusted EBITDA 1, 3 284 179 677 565

Net (loss) income 3 (228) 17 (62) 122

Net (loss) income attributable to shareholders of the Company 3 (226) 18 (57) 127

Normalized earnings attributable to common shareholders 1, 3 64 34 109 84

Basic (loss) earnings per share ($) 3 (2.25) 0.08 (0.90) 0.93

Diluted (loss) earnings per share ($) 2, 3 (2.25) 0.08 (0.90) 0.93

Normalized earnings per share ($) 1, 3 0.60 0.33 1.05 0.81

Net cash flows from operating activities 209 65 519 317

Adjusted funds from operations 1 225 156 427 317

Adjusted funds from operations per share ($) 1 2.11 1.52 4.11 3.07

Purchase of property, plant and equipment and other assets 193 135 523 241

Dividends per common share, declared ($) 0.4800 0.4475 1.3750 1.2825

Dividends per Series 1 preferred share, declared ($) 0.1913 0.1913 0.5738 0.5739





Dividends per Series 11 preferred share, declared ($) 0.3594 - 0.5366 -

As at

September 30, 2019 December 31, 2018

Loans and borrowings including current portion 3,304 2,647

Total assets 8,543 7,569

1 The consolidated financial highlights, except for adjusted EBITDA, normalized earnings attributable to common shareholders, normalized earnings per share, adjusted funds from operations and adjusted funds from operations per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures.

2 Diluted earnings per share was calculated after giving effect to outstanding share purchase options.

3 The comparative periods’ amounts have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16, see Accounting Changes.

See Consolidated Net Income and Results of Operations for discussion of the key drivers of the changes in revenues and other income, adjusted EBITDA, net income and net income attributable to shareholders of the Company.

The changes in basic and diluted earnings per share were driven by the same factors as net income which are discussed in Consolidated Net Income and Results of Operations. The changes in normalized earnings per share and normalized earnings attributable to common shareholders were affected by the same drivers as basic earnings per share, but also the adjustments between earnings per share and normalized earnings per share described under Non-GAAP Financial Measures.

See Liquidity and Capital Resources for discussion of the key drivers of the changes in net cash flows from operating activities. Adjusted funds from operations (AFFO) for the three and nine months ended September 30, 2019 was higher than the comparable periods primarily due to higher adjusted funds from operations from the Alberta facilities driven by favorable pricing and generation, adjusted funds from operations from the new facilities acquired and the commissioning of New Frontier Wind in the fourth quarter of 2018. These increases were partially offset by the impact of higher net finance expense, preferred share dividends, and sustaining capital expenditures in the 2019 periods and the impact of the second quarter Alberta contracted facilities outage as described in Consolidated Net Income and Results of Operations.

The increase in purchases of property, plant and equipment and other assets is discussed in Liquidity and Capital Resources.


SIGNIFICANT EVENTS

Genesee 3 and Keephills 3 swap transaction

On August 2, 2019, the Company announced it had entered into an agreement to divest its 50% share of Keephills 3 to TransAlta Corporation (TransAlta), and to acquire TransAlta’s 50% share of Genesee 3. The transaction closed on October 1, 2019, with a net cost to Capital Power of $10 million, subject to working capital and other closing adjustments. Previously both facilities had been owned and operated under 50/50 Joint Venture Agreements between Capital Power and TransAlta. Following the close of the transaction, Genesee 3 is fully owned and operated by Capital Power and Keephills 3 is fully owned and operated by TransAlta.

Keephills 3 and Genesee 3 are the only supercritical coal facilities in Alberta, with a net capacity of 463 MW and 466 MW, respectively. The swap of interests in the facilities is aligned with Capital Power’s strategic plan to deliver responsible energy for tomorrow. As a result of the transaction, the Company gained full control of the Genesee site, providing strategic freedom and latitude to make decisions that further optimize value for the Genesee units. The transaction is expected to streamline costs and commercial processes and reduce regulatory compliance risk.

The transaction results in an expected pre-tax net loss of approximately $227 million. In the third quarter of 2019, the Company recorded a pre-tax impairment of $401 million on Keephills 3 upon classification as assets held for sale. In the fourth quarter of 2019, the acquisition of the additional 50% of Genesee 3 will be accounted for as a business combination. A gain of approximately $60 million is expected to be recognized on the Company’s existing share of Genesee 3 as a result of the remeasurement of the carrying amount of the Company’s previously owned portion of Genesee 3. In addition, the net reduction to the carrying amounts of the Company’s coal-fired generation assets will result in a one-time adjustment of approximately $114 million to accelerate the recognition of deferred government grant revenue that aligns with the reduction in the new lower carrying amount of coal-fired assets. This relates to the government grant revenue that the Company is receiving over time from the province of Alberta for the 2029 phase-out of coal-fired generation. The Off-coal Agreement is not impacted by the transaction and as a result, compensation will continue to be collected over time and the Company’s ongoing obligations pertaining to the Off-coal Agreement are unchanged. The transaction is expected to be neutral to AFFO over the medium term.

Capital Power announces retirement plans for Brian Vaasjo, President and Chief Executive Officer

On July 29, 2019, the Company announced that Brian Vaasjo, President and Chief Executive Officer, has advised the Board of Directors of his intention to retire in 2020.

The announcement activated an established CEO succession plan developed by Capital Power’s Board of Directors. The Board’s search for a new President and Chief Executive Officer is well under way and the Board will announce a successor in due course. Mr. Vaasjo will continue in his current role, leading the Company and serving on the Board of Directors, until his successor assumes the role. For a period thereafter, Mr. Vaasjo will remain with the Company in an advisory role to support the Board, his successor, and the business and ensure a smooth leadership transition.

Dividend increase

On July 26, 2019, the Company’s Board of Directors approved an increase of 7.3% in the annual dividend for holders of its common shares, from $1.79 per common share to $1.92 per common share. This increased common share dividend will commence with the third quarter 2019 quarterly dividend payment on October 31, 2019 to shareholders of record at the close of business on September 30, 2019.

Accelerated plan for Genesee natural gas capability

On June 18, 2019, the Company announced that it is proceeding with a project that will maximize the flexibility to utilize natural gas as fuel at Genesee, which previously burned primarily coal. The financial impact of this transformation is highly dependant on carbon cost and natural gas price assumptions and is estimated to increase adjusted funds from operations by approximately $10 million in 2020 and $20 million in 2021.

The total cost of the project to completely transform Genesee 1 and 2 to dual-fuel capability and up to 40% gas capability for Genesee 3 is estimated at $50 million with expenditures of $18 million, $19 million, and $13 million in 2019 to 2021, respectively. The project involves adding new gas pipeline infrastructure within the Genesee site and modifications to the Genesee 1 and 2 boilers. The rated capacity of the units will remain the same.

After the units have been transformed to 100% dual-fuel capability, the units can utilize up to 100% natural gas or coal, or a mix of the two. The amount of coal used at any given time, versus natural gas, will be driven by several factors including natural gas and coal prices and carbon costs.

Based on Genesee 1 and 2 at 100% dual-fuel capability and Genesee 3 at 40% natural gas capability, annual greenhouse gas emissions (GHGs) are expected to be reduced by approximately 20% to 33%, assuming operation of the units is between 50% to 100% of hours on natural gas.

The coal operations at the Genesee facility are currently planned to continue up to December 2029, at which time


regulatory requirements will require the Company to discontinue the use of coal. The Genesee facility will continue as a 100% natural gas-fired facility after that time. The Genesee units are already the most efficient coal generating units in Alberta and best performing from an emissions intensity perspective. Under the Genesee Performance Standard program, which commenced in 2016, a 10% improvement in efficiency and performance of the units is targeted by 2021, which improvements will benefit both natural gas and coal operations.

$325 million private placement debt financing

On June 12, 2019, the Company issued $325 million of private placement senior notes which consist of three tranches with 10, 12 and 15-year terms. The 10-year tranche has a principal amount of $210 million that matures in June 2029 with a coupon rate of 4.56%. The 12-year tranche has a $65 million principal amount and matures in June 2031 with a coupon rate of 4.72%. The 15-year tranche has a $50 million principal amount and matures in June 2034 with a coupon rate of 4.96%. The net proceeds from the transaction will primarily be used for refinancing of existing bank indebtedness and for other general corporate purposes.

Acquisition of the Goreway Power Station

On June 4, 2019, the Company completed the acquisition of 100% of the ownership interests in Goreway Power Station Holdings Inc., which owns the Goreway Power Station (Goreway). Goreway is an 875 MW natural gas combined cycle generation facility located in Brampton, Ontario. The purchase price consisted of (i) $410 million of total cash consideration, including working capital and other closing adjustments of $23 million, and (ii) the assumption of $590 million of project level debt.

Financing of the Goreway acquisition consisted of a combination of debt from the Company’s existing credit facilities and equity offerings as described below.

Goreway has a 20-year Accelerated Clean Energy Supply Contract expiring in June 2029 with the Ontario Independent Electricity System Operator (credit ratings of A (high)/Aa3 from DBRS and Moody’s, respectively). Goreway is strategically located in the Greater Toronto Area load centre making it an important asset in Ontario’s electric system and, in combination with the Company’s other Ontario natural gas assets, will provide operating and market synergies over time. The acquisition of Goreway supports the Company’s growth strategy and fully meets the Company’s investment criteria. In addition, the investment contributes to the Company’s dividend growth strategy through immediate AFFO accretion supported by contracted cash flows through mid-2029.

Goreway is expected to generate approximately $124 million of adjusted EBITDA and $50 million of AFFO in 2020. For the 2020-2023 period, average annual adjusted EBITDA and AFFO are estimated to be $127 million and $56 million, respectively. The acquisition of Goreway is forecasted to be $0.27 accretive to AFFO per share in 2020 representing growth of approximately 6%.

Preferred share offering

On May 16, 2019, the Company issued 6 million Cumulative Minimum Rate Reset Preference Shares, Series 11 (Series 11 Shares) at a price of $25.00 per share for gross proceeds of $150 million less issue costs of $4 million. The preferred shares will pay fixed cumulative dividends of $1.4375 per share per annum, yielding 5.75% per annum, payable on the last business day of March, June, September and December of each year, as and when declared by the Board of Directors of Capital Power, for the initial period ending June 30, 2024. The dividend rate will be reset on June 30, 2024 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.15%, provided that, in any event, such rate shall not be less than 5.75%. The Series 11 Shares are redeemable by Capital Power, at its option on June 30, 2024 and every five years thereafter at a value of $25.00 per share.

Holders of the Series 11 Shares will have the right to convert all or any part of their shares into Cumulative Floating Rate Preference Shares, Series 12 (Series 12 Shares), subject to certain conditions, on June 30, 2024 and every five years thereafter. Holders of the Series 12 Shares will be entitled to receive a cumulative quarterly floating dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 4.15%, as and when declared by the Board of Directors of Capital Power. The Series 12 Shares would be redeemable by Capital Power, at its option, on June 30, 2029 and June 30 of every fifth year thereafter at a value of $25.00 per share. The Series 12 Shares would also be redeemable by Capital Power, at its option, on any date after June 30, 2024 excluding June 30 of every fifth year, at a value of $25.50 per share.


Common share offering

In May of 2019, the Company completed a public offering of 4,945,000 subscription receipts (Subscription Receipts), on a bought deal basis, at an issue price of $30.30 per Subscription Receipt (the Offering Price), for total gross proceeds of $150 million less issue costs of $6 million (inclusive of the full exercise of a 645,000 over-allotment option). On June 4, 2019, upon closing of the Goreway acquisition, each Subscription Receipt was converted for one common share of the Company.

Capital Power increases its equity interest in C2CNT; testing of carbon nanotubes in concrete

proceeding

In May 2019, Capital Power committed to increase its equity interest in C2CNT from 5% to 9% by March of 2020.

C2CNT has developed an innovative technology that captures and transforms carbon dioxide into a useful and high-

value product called carbon nanotubes (CNTs) which can be used as an additive to substantially increase the

strength of materials such as concrete, steel and aluminum. Carbon dioxide emissions are avoided by reducing the

amount of material required in addition to the carbon dioxide utilized in the production of CNTs.

Capital Power also has the right to provide notice to exercise two tranches of options in 2020 for an additional 31%

equity interest in C2CNT. If exercised, Capital Power’s equity ownership of C2CNT would increase to a total of 40%.

The investment supports Capital Power’s pursuit of innovative and leading-edge technology to reduce greenhouse

gases. The carbon conversion technology, led by Dr. Stuart Licht, head of the C2CNT team and professor of

chemistry at George Washington University, is currently being tested at demonstration scale at the Alberta Carbon

Conversion Technology Centre located at the Shepard Energy Centre in Calgary that Capital Power co-owns with

ENMAX.

Lehigh Hanson (Lehigh), a subsidiary of HeidelbergCement A.G., a worldwide construction materials company, has

agreed to conduct testing for the utilization of CNTs in concrete at their cost. The testing is expected in the fall of

2019 followed by limited marketing of the CNTs in concrete product in the first half of 2020. Lehigh has also made a

modest financial contribution to C2CNT development.

Additional information on C2CNT is available on Capital Power’s website at:

https://www.capitalpower.com/sustainability/innovation.

Appointments to the Board of Directors

Effective April 26, 2019, Robert Phillips was appointed to the Capital Power Board of Directors.

Effective March 1, 2019, Jane Peverett was appointed to the Capital Power Board of Directors.

Heat rate call option at Arlington Valley

During the first quarter of 2019, the Company entered into a heat rate call option agreement (HRCO) with an investment grade counterparty covering the periods outside of Arlington Valley’s existing summer tolling agreements. The HRCO commenced on April 1, 2019 and terminates December 31, 2025, covering (i) April and November-December 2019 and (ii) January-May and October-December 2020-2025. Pursuant to the HRCO the counterparty has the right to call the plant in exchange for fixed monthly premiums plus reimbursements for fuel at an indexed price, variable operating and maintenance expense and start charges. Adjusted EBITDA and AFFO from the Arlington Valley facility during the period covered by the HRCO is expected to be consistent with the guidance provided at the time the acquisition was announced.



CONSOLIDATED NET INCOME (LOSS) AND RESULTS OF OPERATIONS

The primary factors contributing to the change in consolidated net income (loss) for the three and nine months ended September 30, 2019 compared with the three and nine months ended September 30, 2018 are presented below followed by further discussion of these items.

(unaudited, $ millions) Three months Nine months

Consolidated net income for the periods ended September 30, 2018 1 17 122

Increase (decrease) in adjusted EBITDA:

Alberta commercial facilities and portfolio optimization 12 61

Alberta contracted facilities (5) (16)

Ontario and British Columbia contracted facilities 26 14

U.S. contracted facilities 71 56

Corporate 1 105 (3) 112

Change in unrealized net gains or losses related to the fair value of commodity derivatives and emission credits

43 104

Impairment (401) (401)

Increase in depreciation and amortization expense (52) (105)

Decrease (increase) in foreign exchange loss 1 (9)

Increase in net finance expense (14) (25)

Decrease in income before tax (318) (324)

Change in income tax expense or recovery 73 140

Decrease in net income (245) (184)

Consolidated net loss for the periods ended September 30, 2019 (228) (62)

1 The comparative periods’ amounts have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16, see Accounting Changes.


Results by facility category and other

Three months ended September 30

2019 2018 2019 2018 2019 2018 2019 2018

Electricity generation

(GWh) 1

Facility availability

(%) 2

Revenues and other income (unaudited, $

millions) 11

Adjusted

EBITDA (unaudited, $

millions) 3, 11

Total electricity generation, average facility availability and facility revenues 6,808 5,213 96 98 416 308

Alberta commercial facilities 4

Genesee 3 492 495 96 98 22 27

Keephills 3 450 494 93 100 19 27

Clover Bar Energy Centre 1, 2 and 3 348 217 96 88 18 15

Joffre 150 154 82 97 10 15

Shepard Energy Centre 782 789 100 100 34 36

Halkirk 86 85 95 95 8 7

Clover Bar Landfill Gas - - - 7 - -

Alberta commercial facilities 2,308 2,234 95 96 111 127

Portfolio optimization N/A N/A N/A N/A 70 21

2,308 2,234 95 96 181 148 72 60

Alberta contracted facilities 4

Genesee 1 803 829 96 99

Genesee 2 795 799 100 100

1,598 1,628 98 99 68 70 49 54

Ontario and British Columbia contracted facilities

Island Generation 379 17 99 100 10 10

York Energy 5 3 3 99 100 N/A N/A

East Windsor 2 4 99 99 8 8

Goreway 6 304 N/A 87 N/A 53 N/A

K2 Wind 7 N/A 35 N/A 98 N/A N/A

Kingsbridge 1 15 14 98 98 1 1

Port Dover and Nanticoke 46 43 94 94 7 7

Quality Wind 73 74 96 94 9 10

EnPower 3 10 72 100 - 1

825 200 92 98 88 37 63 37

U.S. contracted facilities

Roxboro, North Carolina 88 87 99 100 10 10

Southport, North Carolina 112 104 84 100 17 15

Decatur Energy, Alabama 709 784 100 100 36 35

Arlington Valley, Arizona 8 878 N/A 100 N/A 61 N/A

Beaufort Solar, North Carolina 8 8 100 100 1 1

Bloom Wind, Kansas 176 152 98 97 13 11

Macho Springs, New Mexico 21 16 97 97 2 2

New Frontier Wind, North Dakota 9 85 N/A 97 N/A 9 N/A

2,077 1,151 99 99 149 74 115 44

Corporate 10 15 15 (15) (16)

Unrealized changes in fair value of commodity derivatives and emission credits 16 51

Consolidated revenues and other income and adjusted EBITDA 517 395 284 179



2019 2018 2019 2018 2019 2018 2019 2018

Electricity generation

(GWh) 1

Facility availability

(%) 2

Revenues and other income (unaudited, $

millions) 11

Adjusted

EBITDA (unaudited, $

millions) 3, 11

Total electricity generation, average facility availability and facility revenues 18,090 14,823 95 96 1,133 911

Alberta commercial facilities 4

Genesee 3 1,494 1,442 99 98 85 70

Keephills 3 1,353 1,348 95 97 72 66

Clover Bar Energy Centre 1, 2 and 3 908 596 95 90 60 44

Joffre 587 397 94 93 49 38

Shepard Energy Centre 2,268 2,169 94 89 110 98

Halkirk 313 320 97 97 32 29

Clover Bar Landfill Gas - - - 29 - -

Alberta commercial facilities 6,923 6,272 95 93 408 345

Portfolio optimization N/A N/A N/A N/A 103 92

6,923 6,272 95 93 511 437 227 166

Alberta contracted facilities 4

Genesee 1 2,196 2,391 89 100

Genesee 2 2,341 2,109 98 92

4,537 4,500 94 96 188 197 134 150


Island Generation 713 27 100 100 29 29

York Energy 5 11 8 100 98 N/A N/A

East Windsor 7 8 99 99 26 26

Goreway 6 380 N/A 90 N/A 69 N/A

K2 Wind 7 N/A 152 N/A 99 N/A N/A

Kingsbridge 1 71 70 98 98 6 6

Port Dover and Nanticoke 210 221 97 97 31 33

Quality Wind 224 250 97 96 29 31

EnPower 13 35 75 95 1 3

1,629 771 96 98 191 128 155 141


Roxboro, North Carolina 238 253 96 96 28 28

Southport, North Carolina 332 333 88 94 49 46

Decatur Energy, Alabama 1,489 2,029 93 98 74 74

Arlington Valley, Arizona 8 2,022 N/A 94 N/A 116 N/A

Beaufort Solar, North Carolina 23 22 100 96 2 2

Bloom Wind, Kansas 520 547 99 97 36 80

Macho Springs, New Mexico 103 96 98 98 12 11

New Frontier Wind, North Dakota 9 274 N/A 96 N/A 29 N/A

5,001 3,280 94 97 346 241 207 151

Corporate 10 47 45 (46) (43)

Unrealized changes in fair value of commodity derivatives and emission credits (3) 29

Consolidated revenues and other income and adjusted EBITDA 1,280 1,077 677 565

1 Gigawatt hours (GWh) of electricity generation reflects the Company’s share of facility output.

2 Facility availability represents the percentage of time in the period that the facility was available to generate power regardless of whether it was running, and therefore is reduced by planned and unplanned outages.


3 The financial results by facility category, except for adjusted EBITDA, were prepared in accordance with GAAP. See Non-GAAP Financial Measures.

4 Based on the nature of future cash flows, the Alberta assets are combined as one CGU for impairment testing purposes. Since the cash flows of Genesee 1 and 2 will remain contracted through 2020, management will continue to present facility results based on the Alberta Commercial and Alberta Contracted groupings through 2020.

5 York Energy is accounted for under the equity method. Capital Power’s share of the facility’s net income is included in income from joint ventures on the Company’s condensed interim consolidated statements of income. Capital Power’s share of the facility’s adjusted EBITDA is included in adjusted EBITDA above. The equivalent of Capital Power’s share of the facility’s revenue was $7 million and $23 million for three and nine months ended September 30, 2019, respectively, compared with $7 million and $22 million for the three and nine months ended September 30, 2018. The facility’s revenues are not included in the above results.

6 Goreway was acquired on June 4, 2019.

7 Capital Power’s share of K2 Wind was disposed of effective December 31, 2018.

8 Arlington Valley was acquired on November 30, 2018.

9 New Frontier Wind was commissioned on December 21, 2018.

10 Corporate revenues were offset by interplant category eliminations.

11 The prior periods’ amounts for the Ontario and British Columbia contracted facilities, as appropriate, have been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16, see Accounting Changes.

Energy prices and hedged positions

Three months ended

September 30

Nine months ended

September 30

Year ended

December 31, 2018 Alberta Unit 2019 2018 2019 2018

Hedged position 1 Percentage sold forward at beginning of period (%) 100 100 80 90 87

Spot power price average $ per MWh 47 55 58 49 50

Realized power price 2 $ per MWh 59 54 58 50 51

Natural gas price (AECO) 3 $ per gigajoule (Gj) 0.99 1.15 1.73 1.42 1.46

1 Hedged position is for the Alberta baseload facilities as well as a portion of Joffre and the uncontracted portion of Shepard.

2 Realized power price is the average price realized as a result of the Company’s commercial contracted sales and portfolio optimization activities.

3 AECO refers to the historical virtual trading hub located in Alberta and known as the Nova Inventory Transfer system operated by TransCanada PipeLines Limited.

Alberta commercial facilities and portfolio optimization

The Alberta spot price averaged $47 per MWh and $58 per MWh for the three and nine months ended September 30, 2019, compared with $55 per MWh and $49 per MWh, respectively, for the corresponding periods in 2018. Lower pricing in the third quarter of 2019 reflected lower temperatures during the summer months of 2019, the impact of lower natural gas pricing, and fewer baseload facility outages. Higher pricing for the nine months ended September 30, 2019, reflected cooler temperatures during the first two quarters of 2019, higher natural gas pricing, lower wind generation and a higher volume of power exports.

Generation was higher for the three and nine months ended September 30, 2019 driven most notably by higher dispatch at Clover Bar Energy Centre and Joffre, offset partly by a planned outage at Joffre in the three months ended September 30, 2019 and forced outages at Keephills 3 in the third quarter of 2019 with none in the comparable period of 2018. Higher generation for the nine months ended September 30, 2019 was also driven by a shorter planned outage and higher dispatch at Shepard Energy Centre in 2019 compared with 2018. Availability for the three months ended September 30, 2019 was consistent with the comparable period in 2018, while availability for the nine months ended September 30, 2019 was higher than the comparable period in 2018, primarily due to the noted shorter planned outage at Shepard Energy Centre and fewer outage hours at Clover Bar Energy Centre partially offset by more forced outages at Keephills 3 in 2019 compared with 2018.

Revenues and other income for the three and nine months ended September 30, 2019 increased compared with the corresponding periods in 2018 primarily due to higher realized power prices and increased generation as described above.

Adjusted EBITDA for the three and nine months ended September 30, 2019 increased compared to the corresponding periods in 2018 driven by the revenues and other income drivers noted above. For the nine months ended September 30, 2019, the increases were also driven by favourable margins earned on export activity, partially offset by the impact of higher natural gas pricing, and lower ancillary services revenues as compared to 2018.


Alberta contracted facilities

Availability for the three months ended September 30, 2019 was lower compared with the corresponding period in 2018 primarily due to a longer unplanned outage in 2019 compared with 2018. Availability for the nine months ended September 30, 2019 was lower compared with the corresponding period in 2018 primarily due to the length of the Genesee 1 planned maintenance outage in 2019 which was four days longer than the Genesee 2 planned outage in 2018.

Generation for the three and nine months ended September 30, 2019 was consistent with the corresponding periods in 2018. Despite the length and timing of the 2019 planned outage, generation for the nine months ended September 30, 2019 was consistent with 2018 partially due to lower dispatch by the PPA buyer in 2018, compared with 2019.

Revenues and other income were lower in the three months ended September 30, 2019 compared with the corresponding period in 2018 primarily due to lower availability incentives as a result of lower Alberta pool prices in the third quarter of 2019, compared with 2018. Revenues and other income were lower in the nine months ended September 30, 2019 compared with the corresponding period in 2018 primarily due to the noted planned outage length as the 2019 results reflect higher net availability penalties which were magnified by higher Alberta power pool prices during the outage period in 2019. The nine months ended September 30, 2019 also reflected higher excess energy payments driven by higher generation and higher running energy payments on higher pricing, partially offset by lower capacity revenues compared with 2018.

Adjusted EBITDA for the three and nine months ended September 30, 2019 was lower than the corresponding periods in 2018 primarily due to the noted factors affecting revenues and other income as well as higher coal costs in 2019. These unfavourable variances are partially offset by higher environmental compliance incentive recoveries in 2019 compared with 2018.


Generation for the three and nine months ended September 30, 2019 was higher than the comparable periods in 2018 primarily due to the acquisition of Goreway (see Significant Events) in the second quarter of 2019 and higher dispatch at Island Generation in 2019, partially offset by the sale of K2 Wind in the fourth quarter of 2018. Availability in 2019 was lower than 2018 primarily due to forced outages at the EnPower facilities as well as the impact on overall availability of a Goreway planned outage in the third quarter of 2019.

Revenues and other income were higher for the three and nine months ended September 30, 2019 compared with the corresponding periods in 2018 primarily due to the acquisition of Goreway in the second quarter of 2019. Adjusted EBITDA for the three and nine months ended September 30, 2019 was higher than the corresponding period in 2018 primarily due to the acquisition of Goreway in 2019, partially offset by the disposal of K2 Wind in the fourth quarter of 2018. Revenues and other income do not include K2 Wind and York Energy, which are accounted for under the equity method.


Generation increased in the three and nine months ended September 30, 2019 compared with the corresponding periods in 2018 primarily due to the addition of Arlington Valley and the commencement of commercial operations at New Frontier Wind in the fourth quarter of 2018, partially offset by lower dispatch at Decatur Energy.

Availability for the three months ended September 30, 2019 was consistent with the corresponding period in 2018 due to the noted additions of Arlington Valley and New Frontier which had strong availability in the third quarter of 2019, offset by numerous forced outages at Southport in 2019 compared with no outages in 2018. Availability decreased in the nine months ended September 30, 2019 compared with the corresponding period in 2018 primarily due to a longer planned outage at Decatur in 2019 compared with 2018 and more frequent forced outages at Southport in 2019 compared with 2018.

Revenues and other income for the three and nine months ended September 30, 2019 are higher than the corresponding periods in 2018 primarily due to the addition of Arlington Valley and the commencement of commercial operations at New Frontier Wind in the fourth quarter of 2018. The increase in revenue and other income for the nine months ended September 30, 2019 compared to the corresponding period in 2018 was partially offset by the impacts of the updated Bloom Wind tax equity investor agreement signed during the second quarter of 2018.

Adjusted EBITDA for the three and nine months ended September 30, 2019 are higher than the corresponding periods in 2018 primarily due to the impacts noted above. The increase in adjusted EBITDA for the nine months ended September 30, 2019 compared to the corresponding period in 2018 was partially offset by higher planned outage costs at Decatur in 2019 compared with 2018.

Corporate

Corporate results include (i) revenues for cost recoveries and other income related to coal compensation from the Province of Alberta, (ii) costs of support services such as treasury, finance, internal audit, legal, human resources, corporate risk management, asset management, and environment, health and safety, and (iii) business development expenses. Note that cost recovery revenues are primarily intercompany revenues that are offset by interplant


category transactions.

Revenues are slightly higher for the nine months ended September 30, 2019 due largely to the recognition of coal compensation revenues being amortized through 2029 beginning in 2019, as compared to an ending year of 2030 for recognition in 2018 as a result of federal regulation shortening the life of coal generation assets by one year.

Net corporate expenditures within adjusted EBITDA for the three months ended September 30, 2019 were lower than the corresponding period in 2018 primarily as a result of lower long-term incentive costs due to lower payout factors for 2019 accrued costs. For the nine months ended September 30, 2019, net corporate expenditures were higher primarily driven by the write-off of wind development projects no longer being developed and higher business development expenses resulting from higher acquisition costs related to Goreway, partially offset by the lower long-term incentive costs due to lower payout factors.

Unrealized changes in fair value of commodity derivatives and emission credits



2019 2018 2019 2018

Revenues and other income Income before tax

Unrealized gains (losses) on Alberta energy derivatives 22 95 (4) -

Unrealized losses on U.S. energy derivatives (6) (42) (6) (42)

Unrealized (losses) gains on natural gas derivatives (3) (3) 11 7

Unrealized gains on emission derivatives 3 1 3 1

Unrealized gains (losses) on emission credits held for trading - - 4 (1)

16 51 8 (35)

(unaudited, $ millions) Nine months ended September 30


2019 2018 2019 2018

Revenues and other income Income before tax

Unrealized (losses) gains on Alberta energy derivatives (38) 51 27 (3)

Unrealized gains (losses) on U.S. energy derivatives 35 (18) 35 (18)

Unrealized (losses) gains on natural gas derivatives (2) (13) 28 4

Unrealized gains on emission derivatives 2 9 2 9

Unrealized losses on emission credits held for trading - - (2) (6)

(3) 29 90 (14)

The Company’s revenues and other income and adjusted EBITDA relating to its Alberta commercial facilities and portfolio optimization and U.S. wind facilities include realized changes in the fair value of commodity derivatives and emission credits. Unrealized changes in the fair value of commodity derivatives and emission credits are excluded from revenues and other income relating to the Alberta commercial facilities and portfolio optimization and U.S. wind facilities and are also excluded from the Company’s adjusted EBITDA metric.

When a derivative instrument settles, the unrealized fair value changes recorded in prior periods for that instrument are reversed from this category. The gain or loss realized upon settlement is then reflected in adjusted EBITDA for the applicable facility category.

During the three months ended September 30, 2019 the Alberta energy portfolio recognized unrealized losses of $4 million, primarily due to the reversal of prior period unrealized net gains on forward sales contracts that settled during the quarter. During the nine months ended September 30, 2019, the Alberta energy portfolio recognized unrealized gains of $27 million compared to unrealized losses of $3 million in 2018. The 2019 gains were primarily due to the impact of increasing forward power prices on net forward purchase contracts while the 2018 losses were due to the reversal of prior period unrealized net gains on forward sales contracts that settled in the third quarter of 2018.

During the three months ended September 30, 2019 and the three and nine months ended September 30, 2018, the Company recorded unrealized losses of $6 million, $42 million and $18 million respectively, on U.S. energy derivatives, primarily as a result of increasing forward prices on forward sales contracts in the respective periods. During the nine months ended September 30, 2019, the Company recorded unrealized gains of $35 million on U.S. energy derivatives, primarily as a result of decreasing forward prices on forward sales contracts in the period.

During the three and nine months ended September 30, 2019 the Company recorded unrealized gains of $11 million and $28 million on natural gas derivatives respectively. These were attributable to net forward purchase contracts being valued against increasing forward natural gas prices, and the reversal of prior periods’ unrealized losses on positions that settled in 2019. Unrealized gains on natural gas derivatives for the three and nine months ended September 30, 2018 were attributable to net forward purchase contracts valued against increasing forward natural gas prices, as well as the reversal of prior period unrealized losses on positions that settled in 2018.


Unrealized gains on emissions derivatives for the three and nine months ended September 30, 2019 and 2018 were due to net forward purchase contracts being valued against increasing forward prices and the impact of the reversal of previously unrealized net losses on positions that settled during the respective periods.

During the three months ended September 30, 2019 the Company recorded unrealized gains on emission credits held for trading, primarily due to the impact of increasing market prices on portfolio holdings. During the nine months ended September 30, 2019 and 2018 the Company recorded unrealized losses of $2 million and $6 million respectively. These losses were due mainly to the reversal of prior period unrealized net gains on emission credits sold during those periods.

Consolidated other expenses and non-controlling interests



2019 2018 2019 2018

Interest on borrowings less capitalized interest (35) (26) (97) (82)

Realized losses on the settlement of interest rate derivatives (1) - (2) -

Other net finance expense – interest on coal compensation from the Province of Alberta, sundry interest, guarantee and other fees 1 3 3 8

(35) (23) (96) (74)

Unrealized gains representing changes in the fair value of interest rate derivatives - 2 - 2

Other net finance expense – amortization and accretion charges, including accretion of deferred revenue pertaining to coal compensation from the Province of Alberta (7) (7) (19) (18)

Total net finance expense (42) (28) (115) (90)

Impairment (401) - (401) -

Depreciation and amortization (135) (83) (355) (250)

Foreign exchange (loss) gain (1) (2) (5) 4

Finance expense and depreciation expense from joint ventures (7) (7) (22) (22)

Income tax recovery (expense) 66 (7) 69 (71)

Net loss attributable to non-controlling interests 2 1 5 5

Net finance expense

Higher net finance expense for the three and nine months ended September 30, 2019 compared with the corresponding periods in the prior year was primarily due to higher loans and borrowings outstanding as a result of the acquisition of Arlington Valley in the fourth quarter of 2018, and the financing related to the acquisition of Goreway in the second quarter of 2019 (see Significant Events).

Impairment

During the three and nine months ended September 30, 2019, the Company recognized a pre-tax impairment of $401 million related to the classification of Keephills 3 as an asset held for sale (see Significant Events).

Depreciation and amortization

Depreciation and amortization for the three and nine months ended September 30, 2019 increased compared with the corresponding periods in the prior year primarily due to the acquisition of Arlington Valley and New Frontier Wind commencing commercial operation in the last quarter of 2018, and the acquisition of Goreway in the second quarter of 2019 (see Significant Events). In addition to this, starting in the first quarter of 2019, Capital Power adjusted the useful lives of assets related to coal to reflect new expected end of life dates resulting from federal regulation changes, including the assets that would be used in a coal-to-gas conversion, to the new estimated life as set out by the federal government. Slightly offsetting these impacts was lower depreciation for Keephills 3 for which depreciation was no longer recorded following the classification of Keephills 3 as an asset held for sale, effective August 2, 2019.

Foreign exchange (loss) gain

For the three months ended September 30, 2019, the exchange rate of the Canadian dollar relative to the U.S. dollar weakened resulting in an unrealized gain on foreign currency purchase contracts mostly offset by unrealized losses on foreign currency sell contracts. For the nine months ended September 30, 2019, the unrealized loss is mostly attributable to net outstanding foreign currency purchase contracts in the first quarter of 2019, during which the Canadian dollar strengthened against the U.S. dollar.

As at September 30, 2018, the Company had outstanding foreign currency purchase contracts totalling US$117 million. For the three months ended September 30, 2018, the exchange rate of the Canadian dollar relative to the U.S. dollar strengthened resulting in an unrealized loss in the period. For the nine months ended September 30, 2018, the exchange rate of the Canadian dollar relative to the U.S. dollar weakened resulting in an unrealized gain.


Finance expense and depreciation expense from joint ventures

Finance expense and depreciation expense from joint ventures includes Capital Power’s share of finance expense and depreciation expense of York Energy and K2 Wind (through to the December 31, 2018 disposal date), which are accounted for under the equity method.

Income tax recovery (expense)

For the three and nine months ended September 30, 2019 income tax recovery was $66 million and $69 million,

respectively, compared to income tax expense of $7 million and $71 million in the corresponding periods of 2018. The

increase in income tax recovery was primarily due to the recognition of a deferred income tax recovery on the

impairment of Keephills 3 in the third quarter of 2019 (see Significant Events), the decrease in the Alberta corporate

income tax rate in the second quarter of 2019, which reduced deferred tax liabilities on the statement of financial

position, and lower amounts attributable to tax-equity interests driven by the updated Bloom Wind tax equity investor

agreement signed in the second quarter of 2018.

With the introduction of the Bill 3 – Job Creation Tax Act on June 28, 2019, the Alberta corporate income tax rate was

reduced from 12% to 8% over four years. Since the Canadian deferred tax assets and liabilities were re-measured, a

deferred income tax recovery of $51 million was recognized during the second quarter of 2019.

Non-controlling interests

Non-controlling interests mostly consist of the Coal Mine partner’s share of the consolidated depreciation expense of the Coal Mine.

COMPREHENSIVE (LOSS) INCOME



2019 2018 2019 2018

Net (loss) income (228) 17 (62) 122

Other comprehensive income (loss):

Net unrealized gains (losses) on derivatives designated as cash flow hedges 19 32 (53) 13

Net unrealized gains on derivatives designated as cash flows hedges – joint ventures - 2 - 3

Net realized (gains) losses on derivatives designated as cash flow hedges reclassified to net income (6) 7 14 8

Net realized losses on derivatives designated as cash flow hedges reclassified to net income – joint ventures - 1 - 2

Unrealized foreign exchange gains (losses) on the translation of foreign operations 11 (8) (22) 12

Total other comprehensive income (loss), net of tax 24 34 (61) 38

Comprehensive (loss) income (204) 51 (123) 160

Other comprehensive income (loss) includes fair value adjustments on financial instruments held by the Company to hedge market risks and which meet the requirements of hedges for accounting purposes. To the extent that such hedges are ineffective, any related gains or losses are recognized in net (loss) income. Other unrealized fair value changes on derivative instruments designated as cash flow hedges and foreign currency translation gains or losses are subsequently recognized in net (loss) income when the hedged transactions are completed and the foreign operations are disposed of or otherwise terminated.


FINANCIAL POSITION

The significant changes in the consolidated statements of financial position from December 31, 2018 to September 30, 2019 were as follows:

(unaudited, $ millions)

As at

September 30, 2019

As at December

31, 2018 Increase

(decrease)

IFRS 16 impact (see Accounting

Changes)

Impact of business

combination and swap

transaction2 Other Primary other changes

Trade and other receivables 1

315 438 (123) (2) 12 (133) Lower receivables are driven by the receipt of the remaining proceeds on disposal of K2 Wind and timing of collection of generation receivables.

Right-of-use assets

93 - 93 86 - 7 Reclassification from property, plant and equipment.

Intangible assets

790 473 317 - 419 (102) Decrease due to depreciation and emission credits used for compliance and transferred to inventory.

Property, plant and equipment 1

5,802 5,356 446 - 198 248 Increase due to capital additions, including Whitla Wind and Cardinal Point Wind, partly offset by depreciation.

Assets net of liabilities held for sale

301 - 301 - 301 -

Net derivative financial instruments liabilities

134 45 89 - 105 (16) Impacts of increasing forward natural gas prices on forward purchase contracts and the settlement of interest rate hedge derivatives and natural gas non-hedge contracts, partially offset by the settlement of foreign exchange non-hedge contracts and the impact of increasing forward power prices on forward power sales contracts.

Loans and borrowings (including current portion)

3,304 2,647 657 - 590 67 Increase primarily due to issuance of private placement senior notes (see Significant Events) and medium-term note, partly offset by net repayment of credit facilities.



As at

September 30, 2019

As at December

31, 2018 Increase

(decrease)

IFRS 16 impact (see Accounting

Changes)

Impact of business

combination and swap

transaction2 Other Primary other changes

Lease liabilities (including current portion)

109 18 91 96 - (5) Decrease primarily due to lease payments.

Net deferred tax liabilities 1

429 351 78 (2) 114 (34) Decrease primarily due to the impact of the reduced Alberta statutory income tax rate and the reclass of tax on the disposal of K2 Wind from deferred tax liability to current tax liability, which was offset by the utilization of non-capital loss carry forwards.

1 Balance as at December 31, 2018 has been restated to reflect the IAS 8 accounting policy change resulting from the transition to IFRS 16, see Accounting Changes.

2 Includes the impacts of assets and liabilities acquired through the Goreway acquisition (see Significant Events) and the impairment and classification of Keephills 3 as held for sale (see Significant Events).

LIQUIDITY AND CAPITAL RESOURCES

(unaudited, $ millions) Nine months ended September 30

Cash inflows (outflows) 2019 2018 Change

Operating activities 519 317 202

Investing activities (738) (168) (570)

Financing activities 175 (161) 336

Operating activities

Cash flows from operating activities for the nine months ended September 30, 2019 increased compared with the same period in 2018 primarily due to cash flows from the acquisitions of Arlington Valley and Goreway (see Significant Events) in the fourth quarter of 2018 and second quarter of 2019, respectively, and the commencement of commercial operations of New Frontier Wind in the fourth quarter of 2018. Cash flows from the Alberta assets were higher in the nine months ended September 30, 2019 when compared to the same period in the previous year driven by increased generation and Alberta power prices. Partially offsetting these increases were a decrease in distributions received from joint ventures and net realized cash losses on certain interest rate derivatives settled during the nine months ended September 30, 2019.

Investing activities

Cash flows used in investing activities for the nine months ended September 30, 2019 increased compared with the same period in 2018 primarily due to the acquisition of Goreway (see Significant Events) in the second quarter of 2019 combined with higher year-to-date spending on the Company’s wind development projects in 2019 compared to 2018. Partially offsetting these increases were cash inflows from the collection of outstanding receivables from the disposal of K2 Wind in the first quarter of 2019.


Capital expenditures and investments

(unaudited, $ millions) Pre-2019

Actual

Nine months ended

September 30, 2019 Actual

Balance of 2019

Estimated 1, 2

Actual or Projected

Total 2 Timing

Genesee 4 and 5 3,4 18 - - 700 Targeted completion currently being reassessed by management

New Frontier Wind 5 174 2 - 176 Completed in December 2018

Whitla Wind 6 71 226 36 340 Targeted completion in the fourth quarter of 2019

Cardinal Point Wind 7 28 183 53 295 Targeted completion in March of 2020

Commercial initiatives 8 - 44 23 98

Development sites and projects 15 2 -

Subtotal growth projects 457 112

Sustaining – facility maintenance excluding Genesee mine

55

Sustaining – Genesee mine maintenance and lands

8

Total capital expenditures 9 520

Emission credits held for compliance 11

Capitalized interest (8)

Purchase of property, plant and equipment and other assets 523

1 The Company’s 2019 estimated capital expenditures include only expenditures for previously announced growth projects and exclude other potential new development projects.

2 Projected capital expenditures to be incurred over the life of the projects for Genesee 4 and 5, New Frontier Wind, Whitla Wind and Cardinal Point Wind are based on management’s estimates. Projected capital expenditures for development sites are not reflected beyond the current period until specific projects reach the advanced development stages and projected capital expenditures for commercial initiatives are not reflected beyond the current period.

3 Excludes interest to fund construction and refundable transmission system contribution payments.

4 Continuation and timing of the Genesee 4 and 5 project will be considered once sufficient Alberta market certainty exists and new generation is required in Alberta to balance supply and demand.

5 New Frontier Wind began commercial operations in December 2018. The finalization of construction activities is occurring during 2019. Projected total cost excludes a $19 million (US$15 million) developer fee paid to a subsidiary of the Company.

6 The original projected total construction cost for Whitla Wind was expected to be in the range of $315 million to $325 million. Actual project costs are now expected to exceed that range primarily driven by foreign exchange impacts on U.S. dollar costs. These amounts are partially economically hedged by forward U.S. currency purchases which have a fair value of $1 million at September 30, 2019 (recorded within current derivative instruments assets as foreign exchange non-hedges) as well as realized foreign exchange gains on forward currency purchases settled in the nine months ended September 30, 2019 of $7 million recorded in net income. The remaining foreign exchange differential is driven by movements in the U.S dollar to Canadian dollar foreign exchange rate between the bid date of Whitla Wind into the initial Alberta REP and the date that Whitla Wind was awarded the contract, which were not hedged.

7 The projected total cost for Cardinal Point Wind reflects the midpoint of the expected range of construction costs of $289 million to $301 million (US$236 million to US$246 million).

8 Commercial initiatives include the combustion turbine upgrade project for Decatur Energy with capital expenditures incurred of $24 million (US$18 million). This project will result in an additional 30MW of generation and was completed in the second quarter of 2019. Commercial Initiatives also includes expected spending on the Company’s Genesee dual-fuel project (see Significant Events) and the Genesee Performance Standard project as well as various other projects designed to either increase the capacity or efficiency of their respective facilities or to reduce emissions.

9 Capital expenditures include capitalized interest. Capital expenditures excluding capitalized interest are presented on the consolidated statements of cash flows as purchase of property, plant and equipment and other assets.


Financing activities

The cash flows from financing activities for the nine months ended September 30, 2019 primarily reflected the net issuance of loans and borrowings, issuance of common and preferred shares (see Significant Events), repurchase of common shares and payment of common and preferred share dividends.

The Company’s credit facilities consisted of:


Maturity timing

As at September 30, 2019 As at December 31, 2018

Total facilities

Credit facility

utilization Available Total

facilities

Credit facility

utilization Available

Committed credit facilities 2020/2024 1,250 1,150

Letters of credit outstanding 101 99

Bankers’ acceptances outstanding 250 396

Bank loans outstanding 1 149 218

1,250 500 750 1,150 713 437

Bilateral demand credit facilities N/A 326 200

Letters of credit outstanding 143 172

326 143 183 200 172 28

Demand credit facilities N/A 25 - 25 25 - 25

1,601 643 958 1,375 885 490

1 U.S. dollar denominated bank loans outstanding totaling US$112 million (December 31, 2018 – US$160 million).

As at September 30, 2019, the committed credit facility utilization decreased $213 million compared with the utilization as at December 31, 2018, due to decreased bankers’ acceptances and U.S. dollar bank loans. In the fourth quarter of 2018 the Company secured a committed non-revolving $150 million credit facility for a period of up to 12 months, which was fully repaid and closed in June 2019. In the second quarter of 2019, the $1.0 billion of committed credit facilities were extended 1-year to mature in July 2024, and the Company secured a committed non-revolving $250 million credit facility for a period of up to 12 months, or June 2020. The available credit facilities provide the Company with adequate funding for ongoing development projects.

The Company has a corporate credit rating of BBB- with a stable outlook from Standard & Poor’s (S&P). The BBB rating category assigned by S&P is the fourth highest rating of S&P’s ten rating categories for long-term debt obligations. According to S&P, a BBB corporate credit rating exhibits adequate capacity to meet financial commitments, however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments.

The Company has a corporate credit rating of BBB (low) with a stable outlook from DBRS Limited (DBRS). The BBB rating category assigned by DBRS is the fourth highest rating of DBRS’ ten rating categories for long-term debt obligations. According to DBRS, long-term debt rated BBB is of adequate credit quality and the capacity of the payment of financial obligations is considered acceptable but the entity is vulnerable to future events.

The above credit ratings from S&P and DBRS are investment grade credit ratings which enhance Capital Power’s

ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.

Future cash requirements

The following estimates of future cash requirements are subject to variable factors including those discussed in Forward-looking Information. Capital Power’s expected cash requirements for 2019 include:

(unaudited, $ millions) Nine months ended September 30, 2019

actual Balance of 2019

estimated

Total 2019 expected cash

requirements

Repayment of debt payable 1 286 14 300

Capital expenditures – sustaining 58 23 81

Capital expenditures – ongoing growth projects 457 112 569

Common share dividends 2 139 51 190

Preferred share dividends 36 12 48

976 212 1,188

1 Excludes repayment of credit facilities.

2 Includes 7.3% annual dividend growth (see Significant Events).


The Company uses a short-form base shelf prospectus to provide it with the ability, market conditions permitting, to obtain new debt and equity capital from external markets when required. Under the short-form base shelf prospectus, Capital Power may raise up to $3 billion by issuing common shares, preferred shares, subscription receipts exchangeable for common shares and/or other securities of the Company and/or debt securities. This prospectus expires in June 2020.

If the Canadian and U.S. financial markets become unstable, Capital Power’s ability to raise new capital to meet its financial requirements, and to refinance indebtedness under existing credit facilities and debt agreements may be adversely affected. Capital Power has credit exposure relating to various agreements, particularly with respect to its PPA, energy supply contract, trading and supplier counterparties. While Capital Power continues to monitor its exposure to its significant counterparties, there can be no assurance that all counterparties will be able to meet their commitments.

Off-statement of financial position arrangements

As at September 30, 2019, the Company has $244 million of outstanding letters of credit for collateral support for trading operations, conditions of certain service agreements and to satisfy legislated reclamation requirements. If the Company were to terminate these off-statement of financial position arrangements, the penalties or obligations would not have a material impact on the Company’s financial condition, results of operations, liquidity, capital expenditures or resources.

Capital resources

(unaudited, $ millions) As at


Loans and borrowings 3,304 2,647

Lease liabilities 1 109 18

Less cash and cash equivalents (133) (182)

Net debt 3,280 2,483

Share capital 3,450 3,200

Deficit and other reserves (496) (190)

Non-controlling interests 38 43

Total equity 2,992 3,053

Total capital 6,272 5,536

1 Includes the current portion disclosed within deferred revenue and other liabilities.

CONTINGENT LIABILITIES AND PROVISIONS

Contingent liabilities

The Company and its subsidiaries are subject to various legal claims that arise in the normal course of business. Management believes that the aggregate contingent liability of the Company arising from these claims is immaterial and therefore no provision has been made.

Line Loss Rule Proceeding provision

Capital Power participated in the Line Loss Rule (LLR) Proceeding before the Alberta Utilities Commission (AUC) regarding loss factors that form the basis for certain transmission charges paid by Alberta generators, including Capital Power. The LLR Proceeding addressed the replacement of the non-compliant LLR as well as the possible correction of line loss charges and credits for the years 2006 up to (but not including) 2017.

The Company is participating in legal or regulatory processes rendering the final outcome of the LLR Proceeding still unknown. However, based on current AUC decisions, Capital Power would incur additional charges related to transmission amounts of historical periods and, as such, recorded a current provision of $9 million during the fourth quarter of 2017 pertaining to the estimated net liability for its currently held Alberta assets. The recorded provision reflects the Company’s estimated net liability. However, it is expected that the invoicing process will result in gross billings to Capital Power of which those amounts not attributable to Capital Power will then be recovered from the appropriate parties. The Alberta Electric System Operator has indicated invoicing for the line loss adjustments will not occur until 2021. As a result, the estimated net liability was reclassified from current to non-current provisions in the third quarter of 2019. Upon closing of the acquisition of the additional 50% interest in Genesee 3 and divesture of the Company’s interest in Keephills 3 (see Significant Events) on October 1, 2019, the Company recorded a $6 million increase to the provision in the fourth quarter of 2019, which brings the total estimated net liability to $15 million.


RISKS AND RISK MANAGEMENT

There have been no material changes in the nine months ended September 30, 2019 to the Company’s business and operational risks as described in the Company’s December 31, 2018 MD&A. Additional information pertaining to climate-related risks and opportunities can be found on the Company’s website within its Climate Change Disclosure report dated February 19, 2019.

ENVIRONMENTAL MATTERS

The Company recorded decommissioning provisions of $361 million as at September 30, 2019 ($259 million as at December 31, 2018) for its generation facilities and the Genesee Coal Mine as it is obliged to remove the facilities at the end of their useful lives and restore the facility and mine sites to their original condition. Decommissioning provisions for the Genesee Coal Mine are incurred over time as new areas are mined, and a portion of the liability is settled over time as areas are reclaimed prior to final pit reclamation. The timing of reclamation activities could vary and the amount of decommissioning provisions could change depending on potential future changes in environmental regulations and the timing of any facility fuel conversions.

The Company has forward contracts to purchase environmental credits totaling $617 million and forward contracts to sell environmental credits totaling $572 million in future years. Included within these forward purchases and sales are net purchase amounts which will be used by the Company to comply with applicable environmental regulations and net sales amounts related to other emissions trading activities.

REGULATORY MATTERS

Ontario’s Independent Electric System Operator (the “IESO”) unexpectedly announced in July 2019 that it was cancelling further work on a broad capacity market framework. In reviewing its long-term planning outlook, the IESO advised that it expects sufficient capacity to exist in the market for the next ten-year period particularly if resources are re-acquired when their existing contracts expire. The process to recontract assets, including those owned by the Company, is expected to commence late 2019 or early 2020 and is likely to include a combination of bilateral contract extensions and competitive processes.

On October 31, 2018, the Government of Ontario passed Bill 4, the Cap and Trade Cancellation Act, 2018. Bill 4 repealed the Climate Change Mitigation and Low-carbon Economy Act, 2016, and set out the legal framework for a wind-down of the Cap and Trade program. The Federal Government Greenhouse Gas Pollution Pricing Act (GGPPA) imposes a carbon pricing system on Ontario and other provinces that do not have an equivalent system in place to meet targeted Greenhouse Gas (GHG) reduction levels. On July 4, 2019, the Government of Ontario published the final Greenhouse Gas Emissions Performance Standards (Ontario Regulation 241/19) and the regulation also came into effect on the day it was filed. However, the first compliance period is not until the Federal Government removes Ontario from Part 2 of Schedule 1 of the Federal GGPPA. As such, the GGPPA will remain in effect in Ontario until 2022. The PPAs for York Energy, East Windsor and Goreway have a provision that triggers a contractual amendment, the effect of which will enable recovery of any imposed federal carbon compliance costs. Accordingly, the Company does not believe the implementation of a federal carbon pricing system or any potential provincial GHG system will have a material adverse effect on its financial condition and results of operations.

On April 16, 2019, the Province of Alberta held an election resulting in the United Conservative Party (UCP) forming a majority government to replace the previous New Democratic Party majority government. Premier Jason Kenney has appointed a Cabinet and the new Government has initiated consultations and action on a number of items that had been identified in the UCP platform. On July 24, the Government of Alberta announced its decision to maintain the energy-only market and advised that it will table the necessary legislation and amend regulations to stop the implementation of the capacity market as soon as possible. Capital Power remains well positioned to compete in Alberta’s energy-only market through our market and commodity management expertise, our young, diverse and efficient fleet of assets, and our pipeline of development projects for which regulatory approvals have already been received. In July, the Government initiated its process to develop the new Technology Innovation and Emissions Reduction (TIER) framework, which will replace the current Carbon Competitiveness and Incentive Regulation (CCIR) as the carbon management framework for large emitters. Capital Power participated in the TIER consultation process, and Management’s understanding continues to be that the carbon framework governing the electricity sector will continue to establish carbon compliance obligations for emissions from electricity generation relative to a “best natural gas” emissions intensity standard similar to the existing CCIR. The TIER legislation will be introduced for consideration by the Legislature in the Fall Session and is expected to be effective January 1, 2020.

USE OF JUDGMENTS AND ESTIMATES

In preparing the condensed interim consolidated financial statements, management made judgments, estimates and assumptions that affect the application of the Company’s accounting policies and the reported amount of assets, liabilities, income and expenses. Actual results may differ from these estimates. There have been no significant

https://can01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fieta.us9.list-manage.com%2Ftrack%2Fclick%3Fu%3Da56b93cff5b695d2a902de8d0%26id%3Dccc811a117%26e%3Dfb9e30e7e9&data=02%7C01%7C%7C25e066592c7743fa6bc808d708be3ed2%7C3f29db97c84d46658c68ceb447a6376d%7C0%7C0%7C636987485564719348&sdata=OUIVYjNseZrUfoO6O7Sz1xHBB84rYfhpLEH6yN4uKbs%3D&reserved=0

https://can01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fieta.us9.list-manage.com%2Ftrack%2Fclick%3Fu%3Da56b93cff5b695d2a902de8d0%26id%3D7ff73b4987%26e%3Dfb9e30e7e9&data=02%7C01%7C%7C25e066592c7743fa6bc808d708be3ed2%7C3f29db97c84d46658c68ceb447a6376d%7C0%7C0%7C636987485564729336&sdata=b4z5II%2FQZXKlNrMUuagU6IZJXpJNtItIvtdXjWw2b78%3D&reserved=0


changes to the Company’s use of judgments and estimates as described in the Company’s December 31, 2018 MD&A, other than those judgments made as a part of the adoption of new accounting standards in the first quarter of 2019, as described under Accounting Changes.

ACCOUNTING CHANGES

Effective January 1, 2019

The Company adopted one new accounting standard as issued by the International Accounting Standards Board (IASB). The standard and impact to Capital Power were:

Standard Description Impact to Capital Power and current implementation status

Effective Date

Leases (IFRS 16) The new standard which replaced IAS 17 – Leases addresses the recognition, measurement, presentation and disclosure of leases. IFRS 16 provides a single lessee accounting model requiring lessees to recognize right-of-use assets and lease liabilities for all leases previously classified as operating leases, including but not limited to, office space leases and land leases. There are no changes to lessor accounting under the new standard. However, the criteria for assessing whether a contract contains a lease have changed.

The Company elected not to grandfather lease assessments, as previously assessed under IAS 17 and IFRIC 4 – Determining Whether an Arrangement Contains a Lease. Management reviewed all contracts and existing lease arrangements to determine the impact of the IFRS 16 adoption.

For contracts determined to contain leases with the Company as the lessee under IFRS 16, the Company elected to apply the modified retrospective approach where the lessee does not restate comparative figures and the cumulative effect of initial application of the standard is recognized in the opening deficit balance. The Company recognized right-of-use assets for the underlying assets and lease liabilities for future lease payments.

Management determined that certain PPAs and energy supply contracts that were previously considered to be finance leases with the Company as the lessor are no longer considered leases under IFRS 16, but rather are now accounted for under IFRS 15 – Revenue from Contracts with Customers. The transition impact for the former finance leases was accounted for retrospectively in accordance with IAS 8 - Accounting Policies, Changes in Accounting Estimates and Errors and treated as a change in accounting policy.

Effective for annual periods beginning on or after January 1, 2019.


The adjustments to the impacted financial statement categories within the consolidated statements of financial position as a result of changes described in the IFRS 16 discussion above are as follows:

Previously stated at

January 1, 2018 IAS 8

Restated as at

January 1, 2018


December 31, 2018 IAS 8

Restated as at

December 31, 2018 IFRS 16

As at January 1, 2019

Assets 1 $ 6,898 $ (79) $ 6,819 $ 7,660 $ (91) $ 7,569 $ 84 $ 7,653

Liabilities 2 3,836 (22) 3,814 4,541 (25) 4,516 90 4,606

Equity 2 $ 3,062 $ (57) $ 3,005 $ 3,119 $ (66) $ 3,053 $ (6) $ 3,047

1 Under IFRS 16, assets related to leases as the lessee represent right-of-use assets and assets related to leases as the lessor represent property, plant and equipment.

2 The opening deficit adjustments above reflect increase to the opening deficit balances, net of deferred tax impacts at a rate of 27% which also impacts the liabilities amounts as reductions to deferred tax liabilities.

The adjustments to the impacted line items within the consolidated statements of income pertaining to the IAS 8 accounting policy change related to the former finance leases where Capital Power was the lessor were:

Three months ended

September 30, 2019

Three months ended

September 30, 2018

Pre-policy

change

Post-policy

change Impact

Pre-policy

change

Post-policy

change Impact

Revenues 478 484 6 367 373 6

Depreciation and amortization (126) (135) (9) (74) (83) (9)

Income tax recovery (expense) 65 66 1 (8) (7) 1

Net (loss) income impact (2) (2)

Nine months ended

September 30, 2019

Nine months ended

September 30, 2018

Pre-policy

change

Post-policy

change Impact

Pre-policy

change

Post-policy

change Impact

Revenues 1,165 1,183 18 943 961 18



Net (loss) income impact (6) (6)


FINANCIAL INSTRUMENTS

The classification, carrying amounts and fair values of financial instruments held at September 30, 2019 and December 31, 2018 were as follows:



Fair value hierarchy

level 1 Carrying amount

Fair value

Carrying amount

Fair value

Financial assets:

Amortized cost

Cash and cash equivalents N/A 133 133 182 182

Trade and other receivables 2 N/A 262 262 385 385

Government grant receivable 3 Level 2 473 430 511 505

Fair value through income or loss

Derivative financial instruments assets – current and non-current See below 189 189 148 148

Fair value through other comprehensive income

Derivative financial instruments assets – current and non-current See below 1 1 11 11

Financial liabilities:

Other financial liabilities

Trade and other payables N/A 314 314 244 244

Loans and borrowings 3 Level 2 3,304 3,352 2,647 2,645

Fair value through income or loss

Derivative financial instruments liabilities – current and non-current See below 191 191 186 186

Fair value through other comprehensive income

Derivative financial instruments liabilities – current and non-current See below 133 133 18 18

1 Fair values for Level 1 financial assets and liabilities are based on unadjusted quoted prices in active markets for identical instruments while fair values for Level 2 financial assets and liabilities are generally based on indirectly observable prices. The determination of fair values for Level 3 financial assets and liabilities is prepared by appropriate subject matter experts and reviewed by the Company’s commodity risk group and by management.

2 Excludes current portion of government grant receivable.

3 Includes current portion.

Risk management and hedging activities

There have been no material changes in the nine months ended September 30, 2019 to the Company’s risk management and hedging activities as described in the Company’s December 31, 2018 MD&A.

The derivative financial instruments assets and liabilities held at September 30, 2019 compared with December 31, 2018 and used for risk management purposes were measured at fair value and consisted of the following:

(unaudited, $ millions) As at September 30, 2019


level

Commodity cash flow

hedges Commodity non-hedges

Interest rate cash flow

hedges

Foreign exchange

non-hedges Total

Derivative financial instruments assets

Level 2 1 164 - 1 166

Level 3 - 24 - - 24

1 188 - 1 190

Derivative financial instruments liabilities

Level 2 (34) (175) (99) (1) (309)

Level 3 - (15) - - (15)

(34) (190) (99) (1) (324)

Net derivative financial instruments (liabilities) assets

(33) (2) (99) - (134)


(unaudited, $ millions) As at December 31, 2018


level

Commodity cash flow

hedges Commodity non-hedges

Interest rate cash flow

hedges

Foreign exchange

non-hedges Total

Derivative financial instruments assets

Level 2 11 120 - 12 143

Level 3 - 16 - - 16

11 136 - 12 159

Derivative financial instruments liabilities

Level 2 (11) (141) (7) (1) (160)

Level 3 - (44) - - (44)

(11) (185) (7) (1) (204)

Net derivative financial instruments (liabilities) assets

- (49)

(7) 11 (45)

Commodity, interest rate and foreign exchange derivatives designated as accounting hedges

Unrealized gains and losses for fair value changes on commodity, interest rate and foreign exchange derivatives that qualify for hedge accounting are recorded in other comprehensive income (loss) and, when realized, are reclassified to net (loss) income as revenues, energy purchases and fuel, finance expense or foreign exchange gains and losses as appropriate. When interest rate derivatives are used to hedge the interest rate on a future debt issuance, realized gains or losses are deferred within accumulated other comprehensive loss and recognized within finance expense over the life of the debt, consistent with the interest expense on the hedged debt.

Commodity, interest rate and foreign exchange derivatives not designated as accounting hedges

The change in fair values of commodity derivatives not designated as hedges is primarily due to changes in forward Alberta power and natural gas prices and their impact on the Alberta portfolio as well as the change in pricing on U.S. trading relating to the swap arrangements on the Company’s U.S. wind generation. Unrealized and realized gains and losses for fair value changes on commodity derivatives that do not qualify for hedge accounting are recorded in net income as revenues or energy purchases and fuel.

Unrealized and realized gains and losses on foreign exchange derivatives and interest rate derivatives that are not designated as hedges for accounting purposes are recorded in net income as foreign exchange gains or losses and net finance expense, respectively.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no significant changes in the Company’s disclosure controls and procedures and internal controls over financial reporting that occurred during the nine months ended September 30, 2019 that have materially affected or are reasonably likely to materially affect the Company’s disclosures of required information and internal control over financial reporting.


SUMMARY OF QUARTERLY RESULTS

(GWh) Three months ended

Electricity generation Sep 30

2019 Jun 30

2019 Mar 31

2019 Dec 31

2018 Sep 30

2018 Jun 30

2018 Mar 31

2018 Dec 31

2017

Total electricity generation 6,808 5,500 5,782 5,406 5,213 4,584 5,026 4,839

Alberta commercial facilities

Genesee 3 492 502 500 372 495 468 479 511

Keephills 3 450 433 470 483 494 434 420 362

Clover Bar Energy Centre 1, 2 and 3 348 264 296 264 217 204 175 92

Joffre 150 205 232 212 154 115 128 119

Shepard Energy Centre 782 679 807 769 789 585 795 694

Halkirk 86 107 120 130 85 103 132 168

Clover Bar Landfill Gas - - - - - - - 2

2,308 2,190 2,425 2,230 2,234 1,909 2,129 1,948


Genesee 1 803 556 837 877 829 751 811 860

Genesee 2 795 698 848 850 799 647 663 864

1,598 1,254 1,685 1,727 1,628 1,398 1,474 1,724


Island Generation 379 166 168 - 17 - 10 3

York Energy 3 4 4 2 3 3 2 2

East Windsor 2 3 2 1 4 2 2 1

Goreway 304 76 N/A N/A N/A N/A N/A N/A

K2 Wind N/A N/A N/A 70 35 41 76 57

Kingsbridge 1 15 20 36 33 14 20 36 37

Port Dover and Nanticoke 46 65 99 78 43 70 108 84

Quality Wind 73 77 74 112 74 98 78 117

EnPower 3 5 5 3 10 11 14 13

825 416 388 299 200 245 326 314


Roxboro, North Carolina 88 88 62 74 87 90 76 86

Southport, North Carolina 112 121 99 106 104 118 111 120

Decatur Energy, Alabama 709 372 408 674 784 576 669 425

Arlington Valley, Arizona 878 750 394 87 N/A N/A N/A N/A

Beaufort Solar, North Carolina 8 9 6 5 8 8 6 6

Bloom Wind, Kansas 176 169 175 164 152 197 198 190

Macho Springs, New Mexico 21 43 39 31 16 43 37 26

New Frontier Wind, North Dakota 85 88 101 9 N/A N/A N/A N/A

2,077 1,640 1,284 1,150 1,151 1,032 1,097 853


(%) Three months ended

Facility availability Sep 30

2019 Jun 30

2019 Mar 31

2019 Dec 31

2018 Sep 30

2018 Jun 30

2018 Mar 31

2018 Dec 31

2017

Total average facility availability 96 92 96 94 98 93 96 95

Alberta commercial facilities

Genesee 3 96 100 100 74 98 98 97 100

Keephills 3 93 92 99 100 100 100 92 75

Clover Bar Energy Centre 1, 2 and 3 96 91 97 85 88 90 93 97

Joffre 82 100 100 100 97 90 93 100

Shepard Energy Centre 100 86 97 100 100 68 100 94

Halkirk 95 98 98 98 95 98 98 97

Clover Bar Landfill Gas - - - - 7 78 - 45

95 93 98 93 96 87 96 93


Genesee 1 96 72 100 100 99 100 100 100

Genesee 2 100 95 100 98 100 93 83 100

98 83 100 99 99 97 92 100


Island Generation 99 100 100 100 100 100 100 100

York Energy 99 100 100 100 100 94 100 100

East Windsor 99 99 99 99 99 99 99 97

Goreway 87 99 N/A N/A N/A N/A N/A N/A

K2 Wind N/A N/A N/A 99 98 100 98 98

Kingsbridge 1 98 97 98 99 98 98 98 98

Port Dover and Nanticoke 94 100 99 98 94 99 100 96

Quality Wind 96 98 96 95 94 97 97 96

EnPower 72 97 55 97 100 86 97 96

92 99 98 99 98 98 99 98


Roxboro, North Carolina 99 100 88 97 100 99 88 100

Southport, North Carolina 84 90 91 83 100 95 89 99

Decatur Energy, Alabama 100 81 98 85 100 94 100 89

Arlington Valley, Arizona 100 100 81 94 N/A N/A N/A N/A

Beaufort Solar, North Carolina 100 100 100 97 100 98 93 97

Bloom Wind, Kansas 98 98 99 100 97 96 98 98

Macho Springs, New Mexico 97 99 98 99 97 98 97 98

New Frontier Wind, North Dakota 97 95 96 98 N/A N/A N/A N/A

99 91 92 89 99 95 98 92


Financial results


Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017

Revenues and other income

Alberta commercial facilities and portfolio optimization 181 150 180 150 148 116 173 190

Alberta contracted facilities 68 46 74 71 70 66 61 64

Ontario and British Columbia

contracted facilities 3 88 56 47 52 37 41 50 54

U.S. contracted facilities 149 102 95 63 74 102 65 58

Corporate 1 15 17 15 13 15 15 15 19

Unrealized changes in fair value of commodity derivatives and emission credits 16 (5) (14) (9) 51 29 (51) (118)

517 366 397 340 395 369 313 267

Adjusted EBITDA

Alberta commercial facilities and portfolio optimization 72 71 84 62 60 51 55 60

Alberta contracted facilities 49 32 53 53 54 51 45 47

Ontario and British Columbia

contracted facilities 2, 3 63 48 44 52 37 45 59 60

U.S. contracted facilities 115 54 38 25 44 72 35 30

Corporate (15) (14) (17) (21) (16) (12) (15) (19)

284 191 202 171 179 207 179 178

1 Revenues are offset by interplant category revenue eliminations.

2 The reported Ontario and British Columbia contracted facilities’ adjusted EBITDA includes the adjusted EBITDA from the York Energy joint venture. Prior quarters’ values include Capital Power’s share of K2 Wind which was disposed of effective December 31, 2018.


Quarterly revenues, net income and cash flows from operating activities are affected by seasonal weather conditions, fluctuations in U.S. dollar exchange rates relative to the Canadian dollar, power and natural gas prices, planned and unplanned facility outages and items outside the normal course of operations. Net income is also affected by changes in the fair value of the Company’s power, natural gas, interest rate and foreign exchange derivative contracts.


Financial highlights

(unaudited, $ millions except per share amounts)

Three months ended

Sep 30 2019

Jun 30 2019

Mar 31 2019

Dec 31 2018

Sep 30 2018

Jun 30 2018

Mar 31 2018

Dec 31 2017


Adjusted EBITDA 1, 2, 3, 4 284 191 202 171 179 207 179 178

Net (loss) income 4 (228) 106 60 136 17 66 39 (14)

Net (loss) income attributable to

shareholders of the Company 4 (226) 108 61 138 18 68 41 (11)

Basic (loss) earnings per share ($) 4 (2.25) 0.93 0.49 1.24 0.08 0.55 0.30 (0.21)

Normalized earnings per share ($) 1, 4 0.60 0.14 0.29 0.30 0.33 0.20 0.28 0.23

Net cash flows from operating activities 209 114 286 133 65 109 143 75

Adjusted funds from operations 1 225 85 117 80 156 76 85 94

Adjusted funds from operations per

share ($) 1 2.11 0.82 1.15 0.78 1.52 0.74 0.82 0.90

Purchase of property, plant and equipment and other assets 193 279 51 114 135 66 40 42

1 The consolidated financial highlights, except for adjusted EBITDA, normalized earnings per share, adjusted funds from operations and adjusted funds from operations per share were prepared in accordance with GAAP. See Non-GAAP Financial Measures.

2 The reported Ontario and British Columbia contracted facilities’ adjusted EBITDA includes the adjusted EBITDA from the York Energy joint venture. Prior quarters’ values include Capital Power’s share of K2 Wind which was disposed of effective December 31, 2018.

3 Commencing with the Company’s March 31, 2019 quarter-end, adjusted EBITDA excludes unrealized changes in fair value of commodity derivatives and emission credits which were previously included in adjusted EBITDA. This change was made to better align the Company’s measure of adjusted EBITDA with its other non-GAAP measures, as both the adjusted funds from operations and the normalized earnings per share measures exclude the impacts of unrealized changes in fair value of commodity derivatives and emission credits. Comparative figures have been restated to reflect the above change to the adjusted EBITDA metric.


Three months ended

Spot price averages Sep 30

2019 Jun 30

2019 Mar 31

2019 Dec 31

2018 Sep 30

2018 Jun 30

2018 Mar 31

2018 Dec 31

2017

Alberta power ($ per MWh) 47 57 69 56 55 56 35 22

Alberta natural gas (AECO) ($ per Gj) 0.99 1.17 2.62 1.59 1.15 1.10 1.99 1.73

Capital Power’s Alberta portfolio average realized power price

($ per MWh) 59 55 58 52 54 51 47 46

Factors impacting results for the previous quarters

Significant events and items which affected results for the previous quarters were as follows:

For the quarter ended June 30, 2019, the Company recorded net income attributable to shareholders of $108 million compared to net income attributable to shareholders of $68 million for the quarter ended June 30, 2018. The increase mainly resulted from an income tax recovery of $33 million in the second quarter of 2019 compared to income tax expense of $46 million in the second quarter of 2018 primarily due to a reduction in the Alberta corporate income tax rate enacted in the second quarter of 2019. Further contributing to the increase were unrealized gains on commodity derivatives and emission credits which were $26 million higher in the second quarter of 2019 compared to the second quarter of 2018. These variances were partially offset by higher depreciation and amortization due to New Frontier Wind commencing commercial operation in the last quarter of 2018 and the acquisitions of Arlington Valley and Goreway in the last quarter of 2018 and second quarter of 2019, respectively. In addition, adjusted EBITDA was lower in the second quarter of 2019 compared to the second quarter of 2018, largely due to the timing and length of planned outages and the impact of the Bloom Wind tax equity agreement renegotiation in the second quarter of 2018, offset partially by higher margins earned on the sale of emission credits in the second quarter of 2019.

For the quarter ended March 31, 2019, the Company recorded net income attributable to shareholders of $61 million compared to net income attributable to shareholders of $41 million for the quarter ended March 31, 2018. The


increase compared to the prior quarter mainly resulted from an increase in adjusted EBITDA most notably due to the higher Alberta power pricing averaging $69 per MWh in the first quarter of 2019 compared to $35 per MWh in the first quarter of 2018, offset partially by lower adjusted EBITDA from joint ventures due to the disposal of K2 Wind in December 2018. Other notable impacts included higher unrealized gains on commodity derivatives and emission credits in 2019 which were higher by $35 million, largely offset by higher depreciation and amortization due to the acquisition of Arlington Valley and New Frontier Wind commencing commercial operation in the last quarter of 2018, and increased income tax expense primarily due to higher consolidated income before tax.

For the quarter ended December 31, 2018, the Company recorded net income attributable to shareholders of $138 million compared to net loss attributable to shareholders of $11 million for the quarter ended December 31, 2017. The increase compared to the prior quarter mainly resulted from the $159 million gain on disposal of the Company’s minority owned interest in K2 Wind. In addition, tax expenses were lower by $26 million in the fourth quarter of 2018 as compared to 2017 driven by U.S. federal tax rate decreases in the fourth quarter of 2017 and the resulting reduction in deferred tax assets. These impacts were partially offset by higher unrealized losses on commodity derivatives and emission credits in 2018 which were higher by $35 million.

For the quarter ended September 30, 2018, the Company recorded net income attributable to shareholders of $18 million compared to net loss attributable to shareholders of $7 million for the quarter ended September 30, 2017. Higher net income reflects the recognition of non-cash impairment losses in the third quarter of 2017 totalling $83 million (pre-tax) related to the Company’s Southport, Roxboro and Decatur Energy facilities. The Company did not record an impairment loss in 2018. Favourable net income attributed to shareholders was partially offset by a foreign exchange loss of $2 million in the third quarter of 2018 compared to a foreign exchange gain of $21 million in the third quarter of 2017 reflecting a gain on the revaluation of U.S. dollar denominated debt not hedged for accounting purposes, and income tax expense of $7 million in the third quarter of 2018 compared to income tax recovery of $9 million in the third quarter of 2017. Adjusted EBITDA was higher in the third quarter of 2018 compared to the third quarter of 2017 primarily due to the impact of higher Alberta power prices in 2018 compared with 2017 on the Alberta contracted assets. Losses related to unrealized changes in the fair value of commodity derivatives and emission credits were higher in the third quarter of 2018 compared to the third quarter of 2017 largely as a result of the 2018 impact of increasing forward prices on forward sales contracts relating to U.S. energy derivatives.

For the quarter ended June 30, 2018, the Company recorded net income attributable to shareholders of $68 million compared to $107 million for the quarter ended June 30, 2017. Lower net income reflected the reversal of a previous write-down of deferred tax assets related to the tax benefit associated with the Company’s U.S. income tax loss carryforwards as a result of the acquisition of Decatur Energy and the commissioning of Bloom Wind in the second quarter of 2017. Further contributing to the decrease were higher net finance expenses and depreciation and amortization due to the acquisition of the thermal facilities and Decatur Energy and the receipt of Bloom Wind Project financing in the second quarter of 2017. These variances were partially offset by higher adjusted EBITDA in the second quarter of 2018 compared to the second quarter of 2017 primarily due to the impact of higher Alberta power prices in 2018 compared with 2017 on the Alberta contracted assets, a full quarter of results from the assets acquired in the second quarter of 2017, and higher Bloom Wind revenue due to the renegotiation of the commercial terms within the Bloom Wind tax equity agreement. Non-cash after tax net income related to Bloom Wind increased $15 million driven by tax rate differences while the $44 million increase in adjusted EBITDA was related to timing.

For the quarter ended March 31, 2018, the Company recorded net income attributable to shareholders of $41 million

compared to $46 million for the quarter ended March 31, 2017. The financial results reflected higher unrealized gains

on Alberta energy derivatives in the first quarter of 2017 that resulted from the impact of decreasing forward Alberta

power prices on net forward sales contracts, partially offset by the reversal of prior year unrealized net gains on

forward sales contracts that settled during the first quarter of 2017. Further contributing to the decrease were higher

net finance expenses and depreciation and amortization due to the acquisition of the thermal facilities and Decatur

Energy and the receipt of Bloom Wind Project financing in the second quarter of 2017. Adjusted EBITDA was higher

in the first quarter of 2018 compared to the first quarter of 2017 primarily due to Bloom Wind commencing operations

and acquisition of the thermal facilities and Decatur Energy in the second quarter of 2017.

For the quarter ended December 31, 2017, the Company recorded net loss attributable to shareholders of $11 million compared to net income attributable to shareholders of $27 million for the quarter ended December 31, 2016. The decrease compared to the prior quarter mainly resulted from lower average realized prices on the Alberta portfolio and unrealized losses on the Alberta power portfolio that were primarily due to the reversal of prior period unrealized net gains on forward sales contracts that settled during the period. Adjusted EBITDA was higher quarter over quarter mostly due to the impact of the acquired thermal facilities and Decatur Energy in the second quarter of 2017 and other income related to coal compensation from the Province of Alberta. During the fourth quarter of 2017, the U.S. federal income tax rate decreased as part of the U.S. tax reform and the Company’s U.S. deferred tax assets and liabilities were re-measured. As a result of the re-measurement, the Company recognized $31 million in deferred income tax expense. In the fourth quarter of 2017, the Company also recorded a current provision of $9 million related to the LLR proceeding based on current Module C conclusions.


SHARE AND PARTNERSHIP UNIT INFORMATION

Quarterly common share trading information

The Company’s common shares are listed on the TSX under the symbol CPX and began trading on June 26, 2009.

Three months ended

Sep 30

2019 Jun 30

2019 Mar 31

2019 Dec 31

2018 Sep 30

2018 Jun 30

2018 Mar 31

2018 Dec 31

2017

Share price ($/common share)

High 31.43 32.25 32.44 29.79 29.45 26.00 25.14 25.59

Low 29.31 29.60 26.22 25.33 25.12 23.42 22.15 23.26

Close 30.68 30.15 31.30 26.59 28.51 25.23 24.24 24.49

Volume of shares traded (millions) 18.2 19.6 18.0 25.5 14.8 11.1 14.0 16.9

Outstanding share and partnership unit data

As at October 23, 2019, the Company had 105.170 million common shares, 5 million Cumulative Rate Reset Preference Shares (Series 1), 6 million Cumulative Rate Reset Preference Shares (Series 3), 8 million Cumulative Rate Reset Preference Shares (Series 5), 8 million Cumulative Minimum Rate Reset Preference Shares (Series 7), 6 million Cumulative Minimum Rate Reset Preference Shares (Series 9), 6 million Cumulative Minimum Rate Reset Preference Shares (Series 11), and one special limited voting share outstanding. Assuming full conversion of the outstanding and issuable share purchase options to common shares and ignoring exercise prices, the outstanding and issuable common shares as at October 23, 2019 were 108.559 million. The outstanding special limited voting share is held by EPCOR.

As at October 23, 2019, CPLP had 24.040 million general partnership units outstanding and 89.473 million common limited partnership units outstanding. All of the outstanding general partnership units and the outstanding common limited partnership units are held by the Company.

ADDITIONAL INFORMATION

Additional information relating to Capital Power Corporation, including the Company’s annual information form and other continuous disclosure documents, is available on SEDAR at www.sedar.com.

Condensed Interim Consolidated Financial Statements of


(Unaudited, in millions of Canadian dollars)

Nine months ended September 30, 2019 and 2018

CAPITAL POWER CORPORATION Condensed Interim Consolidated Financial Statements Nine months ended September 30, 2019 and 2018

Condensed Interim Consolidated Financial Statements:

Condensed Interim Consolidated Statements of Income (Loss) 50

Condensed Interim Consolidated Statements of Comprehensive Income (Loss) 51

Condensed Interim Consolidated Statements of Financial Position 52

Condensed Interim Consolidated Statements of Changes in Equity 53

Condensed Interim Consolidated Statements of Cash Flows 55

Notes to the Condensed Interim Consolidated Financial Statements 56


Condensed Interim Consolidated Statements of Income (Loss) (Unaudited, in millions of Canadian dollars, except per share amounts)

Capital Power Corporation Consolidated Financial Statements Q3-2019 50

Three months ended September 30,

Nine months ended September 30,

2019 2018

(note 3)

2019 2018

(note 3)

Revenues $ 484 $ 373 $ 1,183 $ 961

Other income 33 22 97 116

Energy purchases and fuel (126) (173) (221) (300)

Gross margin 391 222 1,059 777

Other raw materials and operating charges (37) (27) (106) (91)

Staff costs and employee benefits expense (41) (39) (121) (107)

Depreciation and amortization (135) (83) (355) (250)

Impairment (note 5) (401) - (401) -

Other administrative expense (27) (22) (84) (68)


Operating (loss) income (251) 49 (13) 265

Net finance expense (42) (28) (115) (90)

(Loss) income from joint ventures (1) 3 (3) 18

(Loss) income before tax (294) 24 (131) 193

Income tax recovery (expense) (note 6) 66 (7) 69 (71)

Net (loss) income $ (228) $ 17 $ (62) $ 122

Attributable to:

Non-controlling interests $ (2) $ (1) $ (5) $ (5)

Shareholders of the Company $ (226) $ 18 $ (57) $ 127

Earnings (loss) per share (attributable to common shareholders of the Company):

Basic (note 7) $ (2.25) $ 0.08 $ (0.90) $ 0.93

Diluted (note 7) $ (2.25) $ 0.08 $ (0.90) $ 0.93

See accompanying notes to the condensed interim consolidated financial statements


Condensed Interim Consolidated Statements of Comprehensive Income (Loss) (Unaudited, in millions of Canadian dollars)


Three months ended September 30,


2019 2018

(note 3)

2019 2018

(note 3)

Net (loss) income $ (228) $ 17 $ (62) $ 122

Other comprehensive income (loss):

Items that are or may be reclassified

subsequently to net (loss) income:

Cash flow hedges:

Unrealized gains (losses) on derivative

instruments1 19 32 (53) 13

Unrealized gains on derivative instruments –

joint ventures2 - 2 - 3

Reclassification of (gains) losses on

derivative instruments to net (loss) income

for the period3 (6) 7 14 8

Reclassification of losses on derivative

instruments to net (loss) income for the

period – joint ventures4 - 1 - 2

Net investment in foreign subsidiaries:

Unrealized gains (losses) 5 11 (8) (22) 12

Total items that are or may be reclassified

subsequently to net (loss) income, net of tax 24 34 (61) 38

Total other comprehensive income (loss), net of

tax 24 34 (61) 38

Total comprehensive (loss) income $ (204) $ 51 $ (123) $ 160

Attributable to:

Non-controlling interests $ (2) $ (1) $ (5) $ (5)

Shareholders of the Company $ (202) $ 52 $ (118) $ 165 1 For the three and nine months ended September 30, 2019, net of income tax expense of $5 million and income tax

recovery of $16 million, respectively. For the three and nine months ended September 30, 2018, net of income tax

expense of $14 million and $7 million, respectively.

2 For the three and nine months ended September 30, 2019, net of income tax expense of nil and for the three and nine

months ended September 30, 2018, net of income tax expense of $1 million.

3 For the three and nine months ended September 30, 2019, net of reclassification of income tax expense of $2 million and reclassification of income tax recovery of $4 million, respectively. For the three and nine months ended September 30, 2018, net of reclassification of income tax recovery of $2 million and $3 million, respectively.

4 For the three and nine months ended September 30, 2019, net of reclassification of income tax recovery of nil. For the three and nine months ended September 30, 2018, net of reclassification of income tax recovery of $1 million.

5 For the three and nine months ended September 30, 2019 and September 30, 2018, net of income tax expense of nil.



Condensed Interim Consolidated Statements of Financial Position (Unaudited, in millions of Canadian dollars)


September 30, 2019

December 31, 2018

(note 3)

Assets

Current assets:

Cash and cash equivalents $ 133 $ 182

Trade and other receivables 315 438

Inventories 225 200

Derivative financial instruments assets (note 8) 72 77

Assets held for sale (note 5) 324 -

1,069 897

Non-current assets:

Other assets 54 66

Derivative financial instruments assets (note 8) 118 82

Government grant receivable 420 459

Deferred tax assets 32 59

Equity-accounted investments 130 142

Right-of-use assets (note 9) 93 -

Intangible assets 790 473

Property, plant and equipment 5,802 5,356

Goodwill 35 35

Total assets $ 8,543 $ 7,569

Liabilities and equity

Current liabilities:

Trade and other payables $ 314 $ 244

Derivative financial instruments liabilities (note 8) 190 90

Loans and borrowings (note 10) 870 456

Deferred revenue and other liabilities 71 62

Provisions 35 54

Liabilities related to assets held for sale (note 5) 23 -

1,503 906

Non-current liabilities:

Derivative financial instruments liabilities (note 8) 134 114

Loans and borrowings (note 10) 2,434 2,191

Lease liabilities (note 9) 103 17

Deferred revenue and other liabilities 529 587

Deferred tax liabilities 461 410

Provisions 387 291

4,048 3,610

Equity:

Equity attributable to shareholders of the Company

Share capital (note 11) 3,450 3,200

Deficit (467) (222)

Other reserves (29) 32

Deficit and other reserves (496) (190)

2,954 3,010

Non-controlling interests 38 43

Total equity 2,992 3,053

Total liabilities and equity $ 8,543 $ 7,569



Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars)


Share Capital

(note 11)

Cash flow

hedges1

Cumulative translation

reserve1

Defined benefit plan

actuarial losses1

Employee benefits reserve Deficit

Equity attributable to

shareholders of the Company

Non-

controlling interests Total

Equity as at

January 1, 2019 (note 3) $ 3,200 $ 7 $ 23 $ (9) $ 11 $ (222) $ 3,010 $ 43 $ 3,053

Accounting policy changes:

Impact of IFRS 16 (note 3)

- - - - - (8) (8) - (8)

Tax impact of IFRS 16 (note 3) - - - - - 2 2 - 2

Adjusted equity as at January 1, 2019 $ 3,200 $ 7 $ 23 $ (9) $ 11 $ (228) $ 3,004 $ 43 $ 3,047

Net loss - - - - - (57) (57) (5) (62)

Other comprehensive loss:

Cash flow derivative hedge losses - (69) - - - - (69) - (69)

Reclassification of losses to net loss - 18 - - - - 18 - 18

Unrealized loss on foreign currency translation - - (22) - - - (22) - (22)

Tax on items recognized directly in equity - 12 - - - - 12 - 12

Other comprehensive loss $ - $ (39) $ (22) $ - $ - $ - $ (61) $ - $ (61)

Total comprehensive loss - (39) (22) - - (57) (118) (5) (123)

Common share dividends (note 11) - - - - - (145) (145) - (145)

Preferred share dividends (note 11) - - - - - (36) (36) - (36)

Tax on preferred share dividends - - - - - (1) (1) - (1)

Issue of share capital 300 - - - - - 300 - 300

Share issue costs (11) - - - - - (11) - (11)

Deferred taxes on share issue costs 1 - - - - - 1 - 1

Common shares purchased (60) - - - - - (60) - (60)

Share-based payments - - - - 1 - 1 - 1

Share options exercised 20 - - - (1) - 19 - 19

Equity as at September 30, 2019 $ 3,450 $ (32) $ 1 $ (9) $ 11 $ (467) $ 2,954 $ 38 $ 2,992

1 Accumulated other comprehensive loss. Other reserves on the statements of financial position are the aggregate of

accumulated other comprehensive loss and the employee benefits reserve.



Condensed Interim Consolidated Statements of Changes in Equity (Unaudited, in millions of Canadian dollars)


Share Capital

(note 11)

Cash flow

hedges1

Cumulative translation

reserve1

Defined benefit plan

actuarial losses1

Employee benefits reserve

Deficit (note 3)

Equity attributable to

shareholders of the Company

Non-

controlling interests Total

Equity as at

January 1, 2018 $ 3,262 $ (39) $ (27) $ (11) $ 10 $ (181) $ 3,014 $ 48 $ 3,062

Accounting policy changes:

Impact of IAS 8

(note 3) - - - - - (79) (79) - (79)

Impact of IFRS 15 - - - - - (44) (44) - (44)

Tax impact of IAS 8 (note 3) - - - - - 22 22 - 22

Tax impact of IFRS 15 - - - - - 11 11 - 11

Adjusted equity as at January 1, 2018 $ 3,262 $ (39) $ (27) $ (11) $ 10 $ (271) $ 2,924 $ 48 $ 2,972

Net income - - - - - 127 127 (5) 122

Other comprehensive income:

Cash flow derivative hedge gains - 20 - - - - 20 - 20

Cash flow derivative hedge gains – joint ventures - 4 - - - - 4 - 4

Reclassification of losses to net income - 11 - - - - 11 - 11

Reclassification of losses to net income – joint ventures - 3 - - - - 3 - 3

Unrealized gain on foreign currency translation - - 12 - - - 12 - 12

Tax on items recognized directly in equity - (12) - - - - (12) - (12)

Other comprehensive income $ - $ 26 $ 12 $ - $ - $ - $ 38 $ - $ 38

Total comprehensive income - 26 12 - - 127 165 (5) 160

Common share dividends (note 11) - - - - - (132) (132) - (132)

Preferred share dividends (note 11) - - - - - (30) (30) - (30)

Tax on preferred share dividends - - - - - (1) (1) - (1)

Common shares purchased (55) - - - - - (55) - (55)

Share-based payments - - - - 1 - 1 - 1

Share options exercised 9 - - - - - 9 - 9

Equity as at September 30, 2018 $ 3,216 $ (13) $ (15) $ (11) $ 11 $ (307) $ 2,881 $ 43 $ 2,924

1 Accumulated other comprehensive loss. Other reserves on the statements of financial position are the aggregate of

accumulated other comprehensive loss and the employee benefits reserve.



Condensed Interim Consolidated Statements of Cash Flows (Unaudited, in millions of Canadian dollars)



2019 2018 (note 3)

Cash flows from operating activities:

Net (loss) income $ (62) $ 122

Non-cash adjustments to reconcile net (loss) income to net

cash flows from operating activities:

Impairment (note 5) 401 -

Depreciation and amortization 355 250

Net finance expense 115 90

Fair value changes on commodity derivative instruments and

emission credits held for trading (90) 14

Foreign exchange losses (gains) 5 (4))

Income tax (recovery) expense (69) 71

Loss (income) from joint ventures 3 (18))

Recognition of government grant deferred revenue (41) (38)

Tax equity attributes (45) (70)

Other items 8 9

Change in fair value of derivative instruments reflected as cash

settlement 36 16

Distributions received from joint ventures 9 24

Interest paid (83) (70)

Other cash items (49) (17)

Change in non-cash operating working capital 26 (62)

Net cash flows from operating activities 519 317

Cash flows used in investing activities:

Purchase of property, plant and equipment and other assets (523) (241)

Business acquisition, net of acquired cash (note 4) (390) -

Government grant received 50 50

Other cash flows from investing activities 7 6

Realized gain on foreign currency derivative instruments 7 -

Change in non-cash investing working capital 111 17

Net cash flows used in investing activities (738) (168)

Cash flows from (used in) financing activities:

Proceeds from issue of loans and borrowings 875 224

Repayment of loans and borrowings (747) (192)

Realized gain on foreign currency derivative instruments - 33

Issue of share capital (note 11) 300 -

Share issue costs (11) -

Proceeds from exercise of share options 19 9

Common shares purchased (note 11) (60) (55)

Dividends paid (note 11) (175) (160)

Capitalized interest paid (8) (3)

Income taxes paid on preferred share dividends (15) (15)

Other cash flows used in financing activities (3) (2)

Net cash flows from (used in) financing activities 175 (161)

Foreign exchange (loss) gain on cash held in a foreign currency (5) 1

Net decrease in cash and cash equivalents (49) (11)

Cash and cash equivalents at beginning of period 182 52

Cash and cash equivalents at end of period $ 133 $ 41



Notes to the Condensed Interim Consolidated Financial Statements September 30, 2019 and 2018 (Unaudited, tabular amounts in millions of Canadian dollars, except share and per share amounts)


1. Reporting entity:

Capital Power Corporation (the Company or Capital Power) develops, acquires, owns and operates power

generating facilities and manages its related electricity and natural gas portfolios by undertaking trading and

marketing activities.

The registered and head office of the Company is located at 10423 101 Street, Edmonton, Alberta, Canada, T5H

0E9. The common shares of the Company are traded on the Toronto Stock Exchange under the symbol “CPX”.

Interim results will fluctuate due to plant maintenance schedules, the seasonal demands for electricity and changes

in energy prices. Consequently, interim results are not necessarily indicative of annual results.

2. Basis of presentation:

These condensed interim consolidated financial statements have been prepared by management in accordance

with International Accounting Standards (IAS) 34, Interim Financial Reporting. The condensed interim consolidated

financial statements do not include all of the information required for full annual financial statements and should

be read in conjunction with the Company’s 2018 annual consolidated financial statements prepared in accordance

with International Financial Reporting Standards (IFRS).

These condensed interim consolidated financial statements have been prepared following the same accounting

policies and methods as those used in preparing the most recent annual consolidated financial statements, except

as outlined in note 3, and have been prepared under the historical cost basis, except for the Company’s derivative

instruments, emission credits held for trading, defined benefit pension assets and cash-settled share based

payments, which are stated at fair value.

These condensed interim consolidated financial statements were approved and authorized for issue by the Board

of Directors on October 25, 2019.

3. Changes in significant accounting policies:

Effective January 1, 2019 (date of initial application), the Company adopted IFRS 16 – Leases. The objective of

this standard is to provide a foundation for users of financial statements to evaluate the amount, timing and

uncertainty of cash flows arising from leases. To meet this objective, the new standard introduces a single lessee

accounting model requiring lessees to recognize right-of-use assets and lease liabilities for all leases previously

classified as operating leases. There are no changes to lessor accounting under the new standard, however the

criteria for assessing whether a contract contains a lease have changed. These assessments now focus on

whether the customer controls the use of the identified asset throughout the period of use. As such, certain

electricity and natural gas supply contracts where the Company was the lessor are no longer considered a lease

under IFRS 16 and the energy revenue is now accounted for under IFRS 15 – Revenue from Contracts with

Customers.

The Company has elected not to grandfather lease assessments, as previously assessed under IAS 17 - Leases

and IFRIC 4 – Determining Whether an Arrangement Contains a Lease. Management reviewed all contracts and

existing lease arrangements in determining the impact of adopting this standard.




3. Changes in significant accounting policies, continued:

Impact on transition to IFRS 16 - Leases as the lessee

The Company is the lessee in various office, equipment and land leases that were previously accounted for as

operating leases. The Company has elected to apply the modified retrospective approach where the lessee will

not restate comparative figures and the cumulative effect of initial application of the standard will be recognized in

the opening deficit balance at January 1, 2019.

The Company is also the lessee in a sale-and-leaseback transaction for the Beaufort Solar facility. The lease was

accounted for as a finance lease under IAS 17 and remains unchanged under the new standard. The carrying

amount of the right-of-use asset and lease liability at January 1, 2019 was determined based on the carrying

amount of the lease asset and liability under IAS 17 immediately before that date.

On initial application, the Company recognized a lease liability of $96 million for future lease payments and a right-

of-use asset of $86 million for the underlying asset with the difference recognized in the opening deficit balance.

IFRS 16 transition impacts are presented in the tables below.

Measurement:

• Right-of-use assets are measured retrospectively, as if this standard had been applied since the

commencement date of each lease, discounted using the Company’s incremental borrowing rate at the date

of initial application.

• Lease liabilities are measured at the present value of the remaining lease payments, discounted using the

Company’s incremental borrowing rate at January 1, 2019. The weighted-average incremental borrowing

rate was 5.72%.

Practical expedients applied:

• The Company grouped leases with reasonably similar characteristics into portfolios and applied appropriate

discount rates to each of these portfolios of leases.

• The Company relied on its assessment of whether leases are onerous by applying IAS 37 – Provisions,

Contingent Liabilities and Contingent Assets immediately before the date of initial application as an

alternative to performing an impairment review. No leases were determined to be onerous.

• Management excluded initial direct costs from the measurement of the right-of-use assets at the date of

initial application.

The following table reconciles the Company’s operating lease obligations at December 31, 2018, as previously

disclosed in the Company’s consolidated financial statements, to the lease liabilities recognized on initial

application of IFRS 16 at January 1, 2019.

Operating lease commitments at December 31, 2018 $ 142

Discounted using the incremental borrowing rate at January 1, 2019 (65)

Add: Equipment lease contracts 19

Add: Finance lease obligation as at December 31, 2018 1 18

Lease liabilities recognized at January 1, 2019 1 $ 114 1 At December 31, 2018, $1 million of current finance lease obligations were reclassified from trade and other

payables to deferred revenue and other liabilities to conform to the current period’s presentation.

Impact on transition to IFRS 16 - Leases as the lessor

Finance leases:

• Management has determined that power purchase arrangements (PPAs) and energy supply contracts for

Kingsbridge 1, Port Dover and Nanticoke and Quality Wind that were previously considered finance leases

with the Company as the lessor are no longer considered leases upon adoption of this standard, but rather

will be accounted for under IFRS 15 – Revenue from Contracts with Customers. The transition impact for

the former finance leases will be treated as a change in accounting policy and accounted for retrospectively

in accordance with IAS 8 - Accounting Policies, Changes in Accounting Estimates and Errors.





Impact on transition to IFRS 16 - Leases as the lessor, continued

Operating leases:

• The Company is the lessor in various PPAs where it operates the facilities under PPAs that convey the right

to the holder of the agreement to use the related property, plant and equipment. As such, the Genesee units

1 and 2, Island Generation, Decatur Energy and Arlington Valley power generation facilities continue to be

accounted for as assets under operating leases as this classification remains unchanged under the new

standard. Management determined that the East Windsor, EnPower and Roxboro PPAs no longer contain

a lease under IFRS 16 and the energy revenues will be accounted for under IFRS 15. This change has no

impact on the Company’s financial statement balances, but will result in additional revenues from contracts

with customers within the Company’s segment information in note 13.

For further disclosure on the Company’s leases, see note 9.

Summarized impacts of IFRS 16 adoption and resulting IAS 8 accounting policy change

The impacts of adopting IFRS 16 on the consolidated statements of financial position as at January 1, 2019 and

2018, inclusive of the related IAS 8 accounting policy changes, were:



Restated as at

January 1, 2018



Restated as at

December 31, 2018

IFRS

16


Assets

Current Assets:

Cash and cash equivalents $ 52 $ - $ 52 $ 182 $ - $ 182 $ - $ 182

Trade and other receivables 278 (23) 255 462 (24) 438 (2) 436

Inventories 120 - 120 200 - 200 - 200

Derivative financial instruments assets 92 - 92 77 - 77 - 77

542 (23) 519 921 (24) 897 (2) 895

Non-current Assets:

Other assets 68 - 68 66 - 66 - 66

Derivative financial instruments assets 79 - 79 82 - 82 - 82

Finance lease receivables 644 (644) - 620 (620) - - -

Government grant receivable 493 - 493 459 - 459 - 459

Deferred tax assets 74 - 74 59 - 59 - 59

Equity-accounted investments in joint ventures 184 - 184 142 - 142 - 142

Right-of-use assets - - - - - - 86 86

Intangible assets 401 - 401 473 - 473 - 473

Property, plant and equipment 4,378 588 4,966 4,803 553 5,356 - 5,356

Goodwill 35 - 35 35 - 35 - 35

Total Assets $ 6,898 $ (79) $ 6,819 $ 7,660 $ (91) $ 7,569 $ 84 $ 7,653





Summarized impacts of IFRS 16 adoption and resulting IAS 8 accounting policy change, continued



Restated as at

January 1, 2018



Restated as at

December 31, 2018

IFRS

16


Liabilities and equity

Current liabilities:

Trade and other payables 1 $ 216 $ - $ 216 $ 245 $ (1) $ 244 $ - $ 244

Derivative financial instruments liabilities 86 - 86 90 - 90 - 90

Loans and borrowings 239 - 239 456 - 456 - 456

Deferred revenue and other liabilities 1 58 - 58 61 1 62 5 67

Provisions 37 - 37 54 - 54 - 54

636 - 636 906 - 906 5 911

Non-current liabilities:

Derivative financial instruments liabilities 56 - 56 114 - 114 - 114

Loans and borrowings 1,907 - 1,907 2,191 - 2,191 - 2,191

Finance lease obligations 1 17 - 17 17 (17) - - -

Lease liabilities 1 - - - - 17 17 91 108

Deferred revenue and other liabilities 581 - 581 587 - 587 (4) 583

Deferred tax liabilities 374 (22) 352 435 (25) 410 (2) 408

Provisions 265 - 265 291 - 291 - 291

3,200 (22) 3,178 3,635 (25) 3,610 85 3,695

Equity:

Share capital 3,262 - 3,262 3,200 - 3,200 - 3,200

Deficit 1 (181) (57) (238) (156) (66) (222) (6) (228)

Other reserves (67) - (67) 32 - 32 - 32

Deficit and other reserves (248) (57) (305) (124) (66) (190) (6) (196)

3,014 (57) 2,957 3,076 (66) 3,010 (6) 3,004

Non-controlling interests 48 - 48 43 - 43 - 43

Total equity 3,062 (57) 3,005 3,119 (66) 3,053 (6) 3,047

Total liabilities and equity $ 6,898 $ (79) $ 6,819 $ 7,660 $ (91) $ 7,569 $ 84 $ 7,653

1 Comparative figures have been reclassified to conform to the current year’s presentation.





IAS 8 accounting policy change – impacts on consolidated statements of income

The adjustments to the impacted line items within the consolidated statements of income (loss) pertaining to the

IAS 8 accounting policy change related to the former finance leases where the Company was the lessor were:

Three months ended

September 30, 2019

Three months ended

September 30, 2018

Pre-policy

change

Post- policy

change Impact

Pre-policy

change

Post-policy

change Impact

Revenues 478 484 6 367 373 6



Net income (loss) impact (2) (2)

Nine months ended

September 30, 2019

Nine months ended

September 30, 2018

Pre-policy

change

Post- policy

change Impact

Pre-policy

change

Post-policy

change Impact

Revenues 1,165 1,183 18 943 961 18



Net income (loss) impact (6) (6)

4. Acquisition of the Goreway Power Station:

On June 4, 2019, a subsidiary of the Company acquired all of the equity interests in Goreway Power Station

Holdings Inc., which owns the Goreway Power Station (Goreway). Goreway is an 875-megawatt natural gas

combined cycle generation facility located in Brampton, Ontario. The purchase price consisted of (i) $410 million

of total cash consideration, including working capital and other closing adjustments of $23 million, and (ii) the

assumption of $590 million of asset level debt.




4. Acquisition of the Goreway Power Station, continued:

The preliminary allocation of the purchase price to the assets acquired and liabilities assumed based on their

estimated fair values is as follows:

June 4, 2019

Cash and cash equivalents $ 20


Inventories 9


Intangible assets 500

Trade and other payables (19)

Loans and borrowings (590)

Derivative financial instrument liabilities1 (105)

Provisions (40)

Deferred tax liabilities (208)

Fair value of net assets acquired $ 410

1 Interest rate swap agreements to hedge the interest on the assumed debt.

The purchase price allocation is preliminary, subject to the finalization of the allocation between property, plant

and equipment and intangible assets, which is expected to occur during the fourth quarter of 2019.

Goreway has a 20-year Accelerated Clean Energy Supply Contract expiring in June 2029 with the Ontario

Independent Electricity System Operator. Goreway is strategically located in the Greater Toronto Area load centre

making it an important asset in Ontario’s electric system and, in combination with the Company’s other Ontario

natural gas assets, will provide operating and market synergies over time. The acquisition of Goreway supports

the Company’s growth strategy, fully meets the Company’s investment criteria and contributes to the Company’s

dividend growth strategy through increased contracted cash flows through mid-2029.

The amount allocated to trade and other receivables for the acquisition represents both the estimated fair value

and the gross contractual amounts receivable. As at September 30, 2019, all of the contractual cash flows

pertaining to the acquired trade and other receivables have been collected.

The asset level debt assumed related to Goreway is a floating-rate bank facility based on prevailing market interest

rates repayable quarterly with principal payments amortizing to 2029. The interest rate risk on this bank facility has

been largely hedged through 2029 by interest rate swaps assumed as part of the acquisition covering 85% of the

debt principal amount. The Company has elected to apply hedge accounting on these interest rate swaps. These

swaps result in an effective fixed interest rate, on that portion of the assumed debt, of 7.4% (including a 1.4%

stamping rate) per annum. The balance of the debt is subject to an interest rate based on the Canadian Dollar

Offered Rate. The assumed bank facility matures in September 2020 at which time the hedging instruments also

have a mandatory settlement. Management expects to extend both the credit facility and the hedging instruments

before the maturity and mandatory settlement in September of 2020.

The results of operations of Goreway are included in the Company’s consolidated statements of income (loss) and

statements of changes in equity from the date of acquisition. Such results of operations and the related assets and

liabilities at the statement of financial position date are included in the consolidated statements of financial position.

Since the acquisition date, the following revenues and net income are included in the consolidated statements of

income (loss) for the three and nine months ended September 30, 2019:

Three months ended

September 30, 2019

Nine months ended

September 30, 2019

Revenues $ 53 $ 69

Net income 10 13




4. Acquisition of the Goreway Power Station, continued:

The consolidated revenues and net loss of the Company including Goreway, had the acquisition occurred at

January 1, 2019, would have been as follows:

Three months ended

September 30, 2019

Nine months ended

September 30, 2019

Revenues $ 484 $ 1,276

Net loss (228) (40)

In conjunction with the acquisition of Goreway, for the three and nine months ended September 30, 2019, the

Company incurred $2 million in acquisition costs which have been recorded on the Company’s consolidated

statements of income as other administrative expenses.

5. Genesee 3 and Keephills 3 swap transaction:

Genesee 3 (G3) and Keephills 3 (K3) are coal and natural gas co-fired generating units in Alberta with a net

capacity of 466 megawatts (“MW”) and 463 MW, respectively. Previously, both generating units were owned and

operated under 50/50 Joint Venture Agreements between Capital Power and TransAlta Corporation (TransAlta).

In August 2019, the Company entered into an agreement to divest its 50% share of K3 to TransAlta, and to acquire

TransAlta’s 50% share of G3 for cash consideration, paid by Capital Power, of $10 million, subject to working

capital and other closing adjustments. Accordingly, the K3 net assets are classified as assets held for sale for the

period ended September 30, 2019. The consideration to be paid approximates the difference in fair value between

the exchanged interests on the date of the transaction.

The transaction closed on October 1, 2019 at an expected pre-tax net loss of approximately $227 million, with

components of the net loss being recognized in the third and fourth quarters of 2019 as disclosed in the table

below.

Recorded during September 2019

Impairment of K3 upon classification as assets held for sale $ (401)

(401)

To be recorded in the fourth quarter of 2019

Gain to be recognized upon remeasurement of CPC’s existing share of

G3 net assets1 60

Accelerated recognition of coal compensation into income 2 114

$ 174

Total net loss on the transaction $ (227)

1 The acquisition of the additional 50% of G3 will be accounted for as a business combination. A gain is expected

to be recognized on the Company’s existing share of G3 as a result of the remeasurement of the carrying

amount to its estimated fair value upon close of the business combination.

2 Currently, the Company is receiving coal compensation from the province of Alberta related to the 2029 phase

out of coal-fired generation that was determined by reference to the carrying amount of these assets. The coal

compensation is being recognized annually through 2029 on a systematic basis that aligns with the

depreciation expense related to coal-fired assets. The net reduction to the carrying amounts of the Company’s

coal-fired generation assets upon close of the transaction will result in a one-time adjustment to accelerate

the recognition of deferred government grant revenue that aligns with the reduction to the new lower carrying

amount of coal-fired assets.




5. Genesee 3 and Keephills 3 swap transaction, continued:

Assets held for sale – Keephills 3

The Company records assets held for sale at the lower of their fair value less costs to sell and their carrying

amount. Comparing the carrying amount of the K3 disposal group to the estimated fair value of the proceeds to be

received, the Company recorded pre-tax impairments of $401 million within the Alberta cash-generating unit in the

three months ended September 30, 2019. The impairment was applied to the carrying amounts of the intangible

assets and property, plant and equipment of the K3 disposal group.

For purposes of calculating the above impairment, the Company used the fair value less costs to sell of K3 as the

recoverable amount of the assets. The fair value less costs to sell was established by the transaction agreement

described above based on the fair value of G3, net of the $10 million payment made by the Company, less the

Company’s estimate of the directly attributable incremental costs related to the disposal. The determination of the

G3 fair value is disclosed below.

At September 30, 2019, the K3 disposal group consisted of assets and liabilities, net of the impairment, as follows:

September 30, 2019

Assets held for sale

Trade and other receivables $ 10

Inventories 9

Other assets 2

Intangible assets 34


$ 324

Liabilities related to assets held for sale

Trade and other payables $ 3

Deferred revenues and other liabilities (current and non-current) 5

Provisions (non-current) 15

$ 23




5. Genesee 3 and Keephills 3 swap transaction, continued:

Acquisition of Genesee 3

On October 1, 2019, the Company acquired an additional 50% interest in G3 increasing its total ownership to

100%. The purchase price consisted of (i) $10 million of total cash consideration, (ii) the exchange of Capital

Power’s 50% interest in K3 of $301 million, and nominal preliminary working capital and other closing adjustments.

The preliminary allocation of the purchase price to the assets acquired and liabilities assumed on acquisition of

the additional 50% share of G3 based on their estimated fair values is as follows:

October 1, 2019

Cash and cash equivalents $ 3


Inventories 8


Increased share of Genesee site shared property, plant and equipment 3 23

Fair value of net assets acquired $ 311

3 Relates to shared assets of the Genesee site for which capital contributions were previously made by

TransAlta.

Measurement of fair values

The fair value measurement of the additional 50% share of G3 is categorized in Level 3 of the fair value hierarchy

based on inputs used in the discounted cash flow model. The Company’s cash flow projections incorporate

estimates of annual plant revenues, expenses and capital expenditures to the end of G3’s useful life in 2039 which

assumes a full conversion to natural gas.

These estimates reflect past experience and the Company’s current view of future generating capacity, fuel

sources and fuel pricing. Consideration is given to externally available information related to future electricity and

fuel pricing inputs when developing assumptions and such external information is used to validate the Company’s

current view of future pricing assumptions. These external sources of information include information from third

party advisory and research firms serving the industry. Alberta power pricing and natural gas pricing assumptions

used in the modelling above are classified in Level 3 of the fair value hierarchy. The table below presents ranges

for the Level 3 inputs over the useful life of G3:

Alberta power prices ($/MWh) $ 57.80 to $ 85.30

Natural gas prices ($/GJ) $ 1.53 to $ 4.02

Fair value of pre-existing interest in G3

The remeasurement to fair value of the Company’s existing 50% of G3 resulted in a gain of $60 million which will

be recorded in net income (loss) in the fourth quarter of 2019.




6. Income tax:

Income tax differs from the amount that would be computed by applying the federal and provincial income tax rates

as follows:

Three months ended

September 30,

Nine months ended

September 30,

2019

2018

(note 3)

2019

2018

(note 3)

Income before tax $ (294) $ 24 $ (131) $ 193

Income tax at the statutory rate of 26.5%1

(2018 – 27.0%) (78) 7 (35) 52

Increase (decrease) resulting from:

Amounts attributable to non-controlling interests and tax-equity interests2 5 4 14 27

Change in unrecognized tax benefits - - 1 -

Non-taxable amounts (1) (2) (4) (10)

Statutory and other rate differences1 8 (1) (45) 2

Other - (1) - -

Income tax (recovery) expense $ (66) $ 7 $ (69) $ 71

1 On June 28, 2019, as a result of the Alberta Government's Bill 3 - Job Creation Tax Cut Act, the Alberta corporate

income tax rate was reduced from 12% to 8% over 4 years. Accordingly, the 2019 statutory tax rate is 26.5%

and will decrease further to 25% for the 2020 year, to 24% for the 2021 year, and to 23% for the 2022 year. Due

to this tax rate decrease, the Canadian deferred tax assets and liabilities were re-measured, resulting in the

recognition of a deferred income tax recovery of $51 million during the three months ended June 30, 2019.

2 During the nine months ended September 30, 2018, the Company recorded a non-taxable, non-cash, one-time

amount attributable to tax-equity interests in Bloom Wind of $15 million (US$11 million) relating to the

renegotiation of certain commercial terms within the Bloom Wind tax equity agreement. This renegotiation

resulted from the reduction of the U.S. Federal corporate tax rate which was effective January 1, 2018. The total

amount recorded reflects an increase in other income of $44 million (US$33 million) net of an increase in income

tax expense of $29 million (US$22 million).




7. Earnings (loss) per share:

Basic earnings (loss) per share

The earnings (loss) and weighted average number of common shares used in the calculation of basic earnings

(loss) per share are as follows:

Three months ended

September 30,

Nine months ended

September 30,

2019

2018

(note 3)

2019

2018

(note 3)

Income (loss) for the period attributable to shareholders of the Company $ (226) $ 18 $ (57) $ 127

Preferred share dividends of the Company1 (14) (10) (37) (31)

Earnings (loss) used in the calculation of basic

earnings (loss) per share $ (240) $ 8 $ (94) $ 96

1 Includes preferred share dividends and related taxes in respect of the three and nine months ended September

30, 2019 and 2018 respectively.

Three months ended

September 30,

Nine months ended

September 30,

2019 2018 2019 2018

Weighted average number of common shares used in the calculation of basic earnings (loss) per share 106,465,965 102,374,301 103,975,042 103,219,849

Diluted earnings (loss) per share

The earnings (loss) used in the calculation of diluted earnings (loss) per share do not differ from the earnings (loss)

used in the calculation of basic earnings (loss) per share for the three and nine months ended September 30, 2019

and 2018. The weighted average number of common shares for the purposes of diluted earnings (loss) per share

reconciles to the weighted average number of common shares used in the calculation of basic earnings (loss) per

share as follows:

Three months ended

September 30,

Nine months ended

September 30,

2019 2018 2019 2018

Weighted average number of common shares used in the calculation of basic earnings (loss) per share 106,465,965 102,374,301 103,975,042 103,219,849

Effect of dilutive share purchase options2 - 384,161 - 297,697

Weighted average number of common shares used in the calculation of diluted earnings (loss) per share 106,465,965 102,758,462 103,975,042 103,517,546

2 For the three and nine months ended September 30, 2019, the average market price of the Company’s common

shares exceeded the exercise price of certain granted share purchase options, but were not included in the

calculation of diluted earnings (loss) per share as they were anti-dilutive. For the three and nine months ended

September 30, 2018, the average market price of the Company’s common shares exceeded the exercise price

of certain granted share purchase options, but had a neutral effect on earnings (loss) per share.




8. Derivative financial instruments and hedge accounting:

Derivative financial and non-financial instruments are held for the purposes of energy purchases, merchant trading

or financial risk management.

The derivative instruments assets and liabilities used for risk management purposes consist of the following:

September 30, 2019

Energy and emission

allowances

Interest rate

Foreign

exchange

cash flow

hedges

non-

hedges

cash flow

hedges

non-

hedges Total

Derivative instruments assets:

Current $ 1 $ 70 $ - $ 1 $ 72

Non-current - 118 - - 118

Derivative instruments liabilities:

Current (16) (78) (95) (1) (190)

Non-current (18) (112) (4) - (134)

Net fair value $ (33) $ (2) $ (99) $ - $ (134)

Net notional buys (sells) (millions):

Megawatt hours of electricity (7) (14)

Gigajoules of natural gas 344

Metric tons of emission allowances 3

Number of renewable energy credits (1)

Interest rate swaps (note 4) $ 863

Forward currency sells (U.S. dollars) $ (70)

Range of remaining contract terms in years 0.1 to 4.3 0.1 to 13.3 1.0 to 1.2 0.1 to 0.2




8. Derivative financial instruments and hedge accounting, continued:

December 31, 2018

Energy and emission

allowances

Interest rate

Foreign

exchange

cash flow

hedges

non-

hedges

cash flow

hedges

non-

hedges Total

Derivative instruments assets:

Current $ 5 $ 60 $ - $ 12 $ 77

Non-current 6 76 - - 82

Derivative instruments liabilities:

Current (9) (73) (7) (1) (90)

Non-current (2) (112) - - (114)

Net fair value $ - $ (49) $ (7) $ 11 $ (45)

Net notional buys (sells) (millions):

Megawatt hours of electricity (7) (14)

Gigajoules of natural gas 138

Metric tons of emission allowances 4

Number of renewable energy credits (14)

Bond forwards $ 250

Interest rate swaps $ 200

Forward currency buys (U.S. dollars) $ 117

Range of remaining contract terms in years 0.1 to 4.0 0.1 to 14.0 0.1 to 0.9 0.7 to 0.9

Fair values of derivative instruments are determined using valuation techniques, inputs, and assumptions as

described in the Company’s 2018 annual consolidated financial statements. It is possible that the assumptions

used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be

material.

Unrealized and realized pre-tax gains and losses on derivative instruments recognized in other comprehensive

income (loss) and net (loss) income are:

Three months ended

September 30, 2019

Three months ended

September 30, 2018

Unrealized

gains (losses)

Realized

gains (losses)

Unrealized

gains (losses)

Realized

(losses) gains

Energy cash flow hedges $ 14 $ 8 $ 56 $ (9)

Energy and emission

allowances non-hedges 4 22 (34) 13

Interest rate cash flow hedges 2 (1) 8 -

Interest rate non-hedges - - 2 (1)

Foreign exchange cash flow

hedges - - (9) -

Foreign exchange non-hedges (2) 1 (2) -




8. Derivative financial instruments and hedge accounting, continued:

Nine months ended

September 30, 2019

Nine months ended

September 30, 2018

Unrealized

(losses) gains

Realized

(losses) gains

Unrealized

gains (losses)

Realized

(losses) gains

Energy cash flow hedges $ (41) $ (18) $ 30 $ (11)

Energy and emission

allowances non-hedges 92 37 (8) 45

Interest rate cash flow hedges1 (10) (2) 10 -

Interest rate non-hedges - - 2 (1)

Foreign exchange cash flow

hedges - - (9) -

Foreign exchange non-hedges (11) 7 (29) 33

1 Interest rate cash flow hedges of $450 million were settled in the nine months ended September 30, 2019 for a

total loss of $18 million which includes $17 million deferred within accumulated other comprehensive (loss)

income to be reclassified to net (loss) income in future periods within the associated net finance expense

pertaining to the hedged note offering.

Realized and unrealized gains and losses relate only to derivative financial instruments. The following realized and

unrealized gains (losses) are included in the Company’s consolidated statements of income (loss) for the three

and nine months ended September 30, 2019 and 2018:

Three months ended

September 30,

Nine months ended

September 30,

2019 2018 2019 2018

Revenues $ 64 $ 55 $ (12) $ 69

Energy purchases and fuel (30) (85) 123 (43)


Net finance expense (1) 1 (2) 1

The Company has elected to apply hedge accounting on certain derivatives it uses to manage commodity price

risk relating to electricity prices and interest rate risk relating to future borrowings. For the three and nine months

ended September 30, 2019, nil and $1 million of losses, respectively, were realized within net finance expense

pertaining to the ineffective portion of hedging derivatives (three and nine months ended September 30, 2018 –

nil).

Net after tax gains and losses related to derivative instruments designated as energy cash flow hedges and interest

rate hedges are expected to settle and be reclassified to net (loss) income in the following periods:

September 30, 2019

Within one year $ (19)

Between 1 – 5 years (14)

After more than 5 years -

$ (33)




9. Leases:

Right-of-use assets

Land Offices Equipment Total

Balance, January 1, 2019 $ 51 $ 28 $ 20 $ 99

Depreciation (3) (2) (1) (6)

Balance, September 30, 2019 $ 48 $ 26 $ 19 $ 93

Lease liabilities

Contractual undiscounted cash flows for lease liabilities:

As at September 30 2019

Within one year $ 10

Between one and five years 35

More than five years 107

Total $ 152

The following table presents amounts recognized in the consolidated statements of income (loss):

Three months ended

September 30, 2019

Nine months ended

September 30, 2019

Interest on lease liabilities $ 1 $ 4

Variable lease payments not included in

the measurement of lease liabilities 2 4

As at September 30, 2019, income from sub-leasing right-of-use assets and expenses related to short-term and

low-value leases was nil.

Facilities under operating leases

The Genesee units 1 and 2, Island Generation, Decatur Energy and Arlington Valley power generation facilities

are accounted for as assets under operating leases.

As at September 30, 2019, the cost of such property, plant and equipment was $2,049 million (December 31, 2018

- $2,006 million), less accumulated depreciation of $501 million (December 31, 2018 - $433 million).

The minimum future rental payments to be received on these PPAs are:

As at September 30 2019

2019 $ 32

2020 170

2021 127

2022 119

2023 47

Thereafter 98

Total $ 593




10. Financing:

On June 12, 2019, the Company completed a $325 million private placement of senior notes consisting of three

tranches with 10, 12 and 15-year terms. The 10-year tranche has a principal amount of $210 million that matures

in June 2029 with a coupon rate of 4.56%. The 12-year tranche has a $65 million principal amount and matures in

June 2031 with a coupon rate of 4.72%. The 15-year tranche has a $50 million principal amount and matures in

June 2034 with a coupon rate of 4.96%.

11. Share capital:

Dividends declared

For the three months ended September 30, For the nine months ended September 30,

2019 2018 2019 2018

Per share Total Per share Total Per share Total Per share Total

Common1 $ 0.4800 $ 51 $ 0.4475 $ 46 $ 1.3750 $ 145 $ 1.2825 $ 132

Preference

Series 1 0.1913 1 0.1913 1 0.5738 3 0.5739 3

Series 3 0.3408 2 0.2875 1 1.0224 6 0.8625 5

Series 5 0.3274 3 0.3274 3 0.9821 9 0.8900 7

Series 7 0.3750 3 0.3750 3 1.1250 9 1.1250 9

Series 9 0.3594 2 0.3594 2 1.0781 6 1.0782 6

Series 11 0.3594 2 - - 0.5366 3 - -

1 On July 26, 2019, the Company’s Board of Directors approved an increase of 7.3% to $1.92 in the annual

dividend per common share effective for the third quarter of 2019.

Dividends paid2

For the three months ended September 30, For the nine months ended September 30,

2019 2018 2019 2018

Per share Total Per share Total Per share Total Per share Total

Common $ 0.4475 $ 48 $ 0.4175 $ 43 $ 1.3425 $139 $ 1.2525 $ 130

2 Preference Shares dividends are declared and paid in the same period.

During the three and nine months ended September 30, 2019, the Company purchased and cancelled 1,635,538

and 2,018,950 of its outstanding common shares at an average exercise price of $30.40 and $29.66 per share for

$50 million and $60 million, respectively (three and nine months ended September 30, 2018 – 504,318 and

2,231,256 for $13 million and $55 million, respectively) under its Toronto Stock Exchange approved normal course

issuer bid.

On May 8, 2019, the Company completed a public offering of 4,945,000 subscription receipts (Subscription

Receipts), on a bought deal basis, at an issue price of $30.30 per Subscription Receipt (the Offering Price), for

total gross proceeds of $150 million less issue costs of $6 million (inclusive of the full exercise of a 645,000 over-

allotment option). On June 4, 2019, upon closing of the Goreway acquisition, each Subscription Receipt was

converted for one common share of the Company.




11. Share capital, continued:

On May 16, 2019, the Company issued 6 million Cumulative Minimum Rate Reset Preference Shares, Series 11

(Series 11 Shares) at a price of $25.00 per share for gross proceeds of $150 million less issue costs of $4 million.

The Series 11 Shares will pay fixed cumulative dividends of $1.4375 per share per annum, yielding 5.75% per

annum, payable on the last business day of March, June, September and December of each year, as and when

declared by the Board of Directors of Capital Power, for the initial period ending June 30, 2024. The dividend rate

will be reset on June 30, 2024 and every five years thereafter at a rate equal to the sum of the then five-year

Government of Canada bond yield and 4.15%, provided that, in any event, such rate shall not be less than 5.75%.

The Series 11 Shares are redeemable by Capital Power, at its option on June 30, 2024 and every five years

thereafter at a value of $25.00 per share.

Holders of the Series 11 Shares will have the right to convert all or any part of their shares into Cumulative Floating

Rate Preference Shares, Series 12 (Series 12 Shares), subject to certain conditions, on June 30, 2024 and every

five years thereafter. Holders of the Series 12 Shares will be entitled to receive a cumulative quarterly floating

dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 4.15%, as

and when declared by the Board of Directors of Capital Power. The Series 12 Shares would be redeemable by

Capital Power, at its option, on June 30, 2029 and June 30 of every fifth year thereafter at a value of $25.00 per

share. The Series 12 Shares would also be redeemable by Capital Power, at its option, on any date after June 30,

2024 excluding June 30 of every fifth year, at a value of $25.50 per share.

12. Financial instruments:

Fair values

Details of the fair values of the Company’s derivative instruments are described in note 8.

The Company’s other short-term financial instruments are classified and measured at amortized cost, consistent

with the methodologies described in the Company’s 2018 annual consolidated financial statements. Due to the

short-term nature of the financial instruments, the fair values are not materially different from their carrying

amounts.

The fair values of the Company’s other long-term financial instruments are determined using the same valuation

techniques, inputs, and assumptions as described in the Company’s 2018 annual consolidated financial

statements. The carrying amount and fair value of the Company’s other financial instruments, which are all

classified and subsequently measured at amortized cost, are summarized as follows:


Fair value

hierarchy level

Carrying

amount Fair value

Carrying

amount Fair value

Government grant receivable1 Level 2 473 430 511 505

Loans and borrowings1 Level 2 3,304 3,352 2,647 2,645

1 Includes current portion.




12. Financial instruments, continued:


Fair value represents the Company’s estimate of the price at which a financial instrument could be exchanged

between knowledgeable and willing parties in an orderly arm’s length transaction under no compulsion to act. Fair

value measurements recognized in the consolidated statements of financial position are categorized into levels

within a fair value hierarchy based on the nature of the valuation inputs and precedence is given to those fair value

measurements calculated using observable inputs over those using unobservable inputs. The determination of fair

value requires judgment and is based on market information where available and appropriate. The valuation

techniques used by the Company in determining the fair value of its financial instruments are the same as those

used as at December 31, 2018.

The fair value measurement of a financial instrument is included in only one of the three levels described in the

Company’s 2018 annual consolidated financial statements, the determination of which is based upon the lowest

level input that is significant to the derivation of the fair value. The Company’s assessment of the significance of a

particular input to the fair value measurement requires judgment which will affect the placement within the fair

value hierarchy levels.

The Company’s policy is to recognize transfers between levels as of the date of the event of change in

circumstances that caused the transfer. The transfers between levels in the fair value hierarchy for the three and

nine months ended September 30, 2019 and the year ended December 31, 2018 are disclosed below within the

continuity of Level 3 balances.

The table below presents the Company’s financial instruments measured at fair value on a recurring basis in the

consolidated statements of financial position, classified using the fair value hierarchy described in the Company’s

2018 annual consolidated financial statements.

September 30, 2019

Level 1 Level 2 Level 3 Total

Derivative financial instruments assets $ - $ 166 $ 24 $ 190

Derivative financial instruments liabilities - (309) (15) (324)

December 31, 2018

Level 1 Level 2 Level 3 Total

Derivative financial instruments assets $ - $ 143 $ 16 $ 159

Derivative financial instruments liabilities - (160) (44) (204)

Valuation techniques used in determination of fair values within Level 3

The Company has various commodity contracts with terms that extend beyond a liquid trading period. As forward

market prices are not available for the full period of these contracts, their fair values are derived using forecasts

based on internal modelling and as a result, are classified within Level 3 of the hierarchy.





Fair value hierarchy, continued

Valuation techniques used in determination of fair values within Level 3, continued

In addition, as at September 30, 2019 and December 31, 2018, the Company holds contracts for the sale of

renewable energy credits (RECs) for which pricing beyond two years is not readily observable and the contracts

are therefore classified in Level 3 of the hierarchy.

The fair values of the Company’s commodity derivatives included within Level 3 are determined by applying a

mark-to-forecast model. The table below presents ranges for the Company’s Level 3 inputs:


REC pricing (per certificate) – Thermal $0.91 $1.09

REC pricing (per certificate) – Solar $215.10 to $413.72 $221.55 to $395.64

Power pricing (per MWh) – Wind $13.84 to $61.35 $15.48 to $70.68

Valuation process applied to Level 3

The valuation models used to calculate the fair values of the derivative financial instruments assets and liabilities

within Level 3 are prepared by appropriate internal subject matter experts and reviewed by the Company’s

commodity risk group and by management. The valuation technique and the associated inputs are assessed on a

regular basis for ongoing reasonability.

The table below presents the impact to fair value of Level 3 derivative instruments based on reasonably possible

alternative assumptions:


REC pricing – Thermal2 $ - $ -

REC pricing – Solar2 - -

Power pricing – Wind2 18 17

2 Reflects the increase or decrease to fair value calculated using a $1 per unit decrease or increase in the input.

Continuity of Level 3 balances

The Company classifies financial instruments in Level 3 of the fair value hierarchy when there is reliance on at

least one significant unobservable input to the valuation model used to determine fair value. In addition to these

unobservable inputs, the valuation model for Level 3 instruments also relies on a number of inputs that are

observable either directly or indirectly. Accordingly, the unrealized gains and losses shown below include changes

in the fair value related to both observable and unobservable inputs. The following table summarizes the changes

in the fair value of financial instruments classified in Level 3:





Fair value hierarchy, continued

Continuity of Level 3 balances, continued

Nine months ended

September 30, 2019

Year ended

December 31, 2018

As at January 13 $ (28) $ 30

Unrealized and realized gains (losses) included in net (loss)

income4 36 (55)

Transfers5 - (5)

Foreign exchange gain 1 2

As at end of period $ 9 $ (28)

Total unrealized gains (losses) for the period included in net

(loss) income4 $ 36 $ (55)

3 The fair value of derivative instruments assets and liabilities are presented on a net basis.

4 Recorded in revenues.

5 Relates to transfer from Level 3 to Level 2 when pricing inputs became readily observable.

All instruments classified as Level 3 are derivative type instruments. Gains and losses associated with Level 3

balances may not necessarily reflect the underlying exposures of the Company. As a result, unrealized gains and

losses from Level 3 financial instruments are often offset by unrealized gains and losses on financial instruments

that are classified in Levels 1 or 2.




13. Segment information:

The Company operates in one reportable business segment involved in the operation of electrical generation

facilities within Canada (Alberta, British Columbia and Ontario) and in the U.S. (North Carolina, New Mexico,

Kansas, Alabama, Arizona and North Dakota), as this is how management assesses performance and determines

resource allocations. The Company also holds a portfolio of wind and solar development sites in the U.S., including

Cardinal Point Wind which is under development in Illinois.

The Company’s results from operations within each geographic area are:

Three months ended September 30, 2019


(note 3)

Canada U.S.

Inter-area

eliminations Total Canada U.S.

Inter-area

eliminations Total

Revenues - external $ 350 $ 134 $ - $ 484 $ 340 $ 33 $ - $ 373

Revenues - inter-area - 4 (4) - 5 8 (13) -

Other income 19 14 - 33 16 6 - 22

Total revenues and

other income $ 369 $ 152 $ (4) $ 517 $ 361 $ 47 $ (13) $ 395

Nine months ended September 30, 2019


(note 3)

Canada U.S.

Inter-area

eliminations Total Canada U.S.

Inter-area

eliminations Total

Revenues - external $ 819 $ 364 $ - $1,183 $ 789 $ 172 $ - $ 961

Revenues - inter-area 20 10 (30) - 9 24 (33) -

Other income 52 45 - 97 46 70 - 116

Total revenues and

other income $ 891 $ 419 $ (30) $1,280 $ 844 $ 266 $ (33) $ 1,077

As at September 30, 2019

As at December 31, 2018

(note 3)

Canada U.S. Total Canada U.S. Total

Property, plant and

equipment $ 4,282 $ 1,520 $ 5,802 $ 3,947 $ 1,409 $ 5,356

Right-of-use assets

(note 9) 57 36 93 - - -

Intangible assets 632 158 790 249 224 473

Goodwill 35 - 35 35 - 35

Other assets 54 - 54 65 1 66

$ 5,060 $ 1,714 $ 6,774 $ 4,296 $ 1,634 $ 5,930




13. Segment information, continued:

The Company’s revenues and other income from contracts with customers are disaggregated by major type of

revenues and operational groupings of revenues:


Alberta

Commercial

Alberta

Contracted

Ontario and

British

Columbia

Contracted

U.S.

Contracted

Total from

contracts

with

customers

Other

sources Total

Energy revenues $ 125 $ 2 $ 78 $ 31 $ 236 $ 234 $ 470

Emission credit

revenues 5 - - 2 7 7 14

Total revenues1 $ 130 $ 2 $ 78 $ 33 $ 243 $ 241 $ 484


Alberta

Commercial

Alberta

Contracted

Ontario and

British

Columbia

Contracted

U.S.

Contracted

Total from

contracts

with

customers

Other

sources Total

Energy revenues $ 461 $ 5 $ 162 $ 119 $ 747 $ 396 $ 1,143

Emission credit

revenues 17 - - 6 23 17 40

Total revenues1 $ 478 $ 5 $ 162 $ 125 $ 770 $ 413 $ 1,183

1 Included within trade and other receivables, as at September 30, 2019, were amounts related to contracts with

customers of $104 million.

Three months ended September 30, 2018 (note 3)

Alberta

Commercial

Alberta

Contracted

Ontario and

British

Columbia

Contracted

U.S.

Contracted

Total from

contracts

with

customers

Other

sources Total

Energy revenues $ 140 $ 2 $ 27 $ 28 $ 197 $ 166 $ 363

Emission credit

revenues 4 - - 2 6 4 10

Total revenues2 $ 144 $ 2 $ 27 $ 30 $ 203 $ 170 $ 373

Nine months ended September 30, 2018 (note 3)

Alberta

Commercial

Alberta

Contracted

Ontario and

British

Columbia

Contracted

U.S.

Contracted

Total from

contracts

with

customers

Other

sources Total

Energy revenues $ 384 $ 6 $ 98 $ 86 $ 574 $ 344 $ 918

Emission credit

revenues 17 - - 6 23 20 43

Total revenues2 $ 401 $ 6 $ 98 $ 92 $ 597 $ 364 $ 961

2 Included within trade and other receivables, as at September 30, 2018, were amounts related to contracts with

customers of $175 million.

14. Comparative figures:

Certain comparative figures have been reclassified to conform to the current year’s presentation.

capital power corporationsignificant events) and fair value adjustments, were $64 million or $0.60...

Documents